false 0001163165 0001163165 2020-11-16 2020-11-16 0001163165 us-gaap:TreasuryStockCommonMember 2020-11-16 2020-11-16 0001163165 cop:SevenpercentdebenturesduetwentytwentyninememberMember 2020-11-16 2020-11-16
 
 
1
 
 
 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C.
 
20549
FORM
8-K
 
CURRENT REPORT
Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
 
Date of Report (date of earliest event reported):
 
November 16, 2020
 
ConocoPhillips
 
(Exact name of registrant as specified in its charter)
Delaware
001-32395
01-0562944
(State or other jurisdiction of
(Commission
(I.R.S. Employer
incorporation)
File Number)
Identification No.)
925 N. Eldridge Parkway
Houston
,
Texas
77079
 
(Address of principal executive offices and zip code)
Registrant’s telephone number,
 
including area code:
 
(
281
)
293-1000
Check the appropriate box below if the Form 8-K filing is intended
 
to simultaneously satisfy the filing obligation of
the registrant under any of the following
 
provisions:
☐
 
Written communications pursuant to Rule 425
 
under the Securities Act (17
 
CFR 230.425)
☐
 
Soliciting material pursuant to
 
Rule 14a-12 under the Exchange Act
 
(17 CFR 240.14a-12)
☐
 
Pre-commencement communications
 
pursuant to Rule 14d-2(b) under the
 
Exchange Act (17 CFR 240.14d-2(b))
☐
 
Pre-commencement communications
 
pursuant to Rule 13e-4(c) under the Exchange
 
Act (17 CFR 240.13e-4(c))
 
Securities registered pursuant to Section 12(b) of the
 
Act:
 
 
Title of each class
Trading symbols
Name of each exchange on which registered
Common Stock, $.01 Par Value
COP
New York Stock Exchange
7% Debentures due 2029
CUSIP – 718507BK1
New York Stock Exchange
 
Indicate by check
 
mark whether the
 
registrant is an
 
emerging growth company
 
as defined in
 
Rule 405 of
 
the Securities
Act of 1933
 
(§230.405 of this
 
chapter) or Rule
 
12b-2 of the
 
Securities Exchange Act of
 
1934 (§240.12b-2 of this
chapter).
 
Emerging growth company
☐
 
 
 
2
 
If an emerging growth company,
 
indicate by check
 
mark if the registrant
 
has elected not
 
to use the extended
 
transition
period for complying with any
 
new or revised financial accounting standards
 
provided pursuant to Section 13(a) of
the Exchange Act.
☐
 
 
 
Item 8.01 Other Events.
ConocoPhillips (the
 
“Company”) is
 
recasting certain financial
 
information included
 
in its 2019
Annual Report on Form 10-K
 
(the “Form 10-K”) which was initially filed with the Securities and
Exchange Commission (“SEC”) on February 18, 2020, to reflect a realignment of the Company’s
segments. The Company managed
 
operations through six operating
 
segments, which are primarily
defined by
 
geographic region,
 
and were
 
previously named
 
the following:
 
Alaska; Lower
 
48;
Canada; Europe and North Africa;
 
Asia Pacific and Middle East; and Other International.
 
Effective with
 
the third
 
quarter of
 
2020, the
 
Company has
 
restructured segments
 
to align
 
with
changes within its
 
internal organization.
 
The Middle East
 
business was realigned
 
from the
 
Asia
Pacific and
 
Middle East segment
 
to the
 
Europe and
 
North Africa segment.
 
The segments have
been renamed the Asia Pacific segment and the Europe, Middle East and North Africa segment.
Attached as Exhibit
 
99.1 of
 
this Current
 
Report on Form
 
8-K are the
 
following portions
 
of the
Form 10-K which
 
were revised to
 
reflect this realignment
 
in segments: Business
 
and Properties
(Items 1
 
and 2), Management’s
 
Discussion and Analysis
 
of Financial
 
Condition and
 
Results of
Operations (Item 7),
 
Financial Statements and
 
Supplementary Data (Item
 
8), and Exhibit,
 
Financial
Statement Schedules
 
(Item 15).
 
The change
 
in segments
 
did not
 
impact previously
 
reported
consolidated net
 
income (loss),
 
net income
 
(loss) attributable to
 
ConocoPhillips, or net
 
income
(loss) attributable to
 
ConocoPhillips per share
 
of common stock.
 
The segment-specific information
presented in
 
exhibit 99.1
 
is consistent
 
with the
 
presentation of
 
segments in
 
the Company’s
Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2020, filed with the
SEC on November 3, 2020.
This Current Report on Form 8-K is being filed only for the purposes described above and all
other information in the Form 10-K
 
remains unchanged. In order to preserve the nature and
character of the disclosures set forth in the Form 10-K, the items included in Exhibit 99.1 of this
Current Report on Form 8-K have been updated solely for matters relating specifically to the
segment realignment and related classifications as described above. No attempt has been made in
this Current Report on Form 8-K to reflect events or occurrences after the date of the filing of the
Form 10-K, on February 18, 2020, and it should not be read to modify or update other
disclosures as presented in the Form 10-K. Therefore, this Current Report on Form 8-K should
be read in conjunction with the Form 10-K and the Company’s filings made with the SEC
subsequent to the filing of the Form 10-K, including the Company’s Quarterly Reports on Form
10-Q
 
for the quarters ended March 31, 2020, June 30, 2020, and September 30, 2020.
 
These
subsequent SEC filings contain important information regarding events, risks, developments and
updates affecting the Company and its expectations that have occurred since the filing of the
Form 10-K.
 
The revised portions of the Form 10-K described above are attached as Exhibit 99.1
hereto and incorporated herein by reference.
 
References in the attached exhibits to the Form 10-
K or parts thereof refer to the Form 10-K for the year ended December 31, 2019, filed on
February 18, 2020, except to the extent portions of such Form 10-K have been revised in this
Current Report on Form 8-K, in which case, they refer to the applicable revised portion in this
 
 
3
 
Current Report on Form 8-K. The information contained herein is not an amendment to, or a
restatement of, the Form 10-K.
 
 
 
 
 
4
 
Item 9.01 Financial Statements and Exhibits.
 
(d)
 
Exhibits
Exhibit No.
 
Description
23.1*
 
 
23.2*
 
 
99.1*
 
 
 
99.2*
 
 
101.INS**
 
Inline XBRL Instance Document.
 
101.SCH**
 
Inline
 
XBRL Schema Document.
 
101.CAL**
 
Inline XBRL Calculation Linkbase Document.
 
101.DEF**
 
Inline XBRL Definition Linkbase Document.
 
101.LAB**
 
Inline XBRL Labels Linkbase Document.
 
101.PRE**
 
Inline XBRL Presentation Linkbase Document.
104*
 
Cover Page
 
Interactive Data
 
File (formatted
 
as Inline
 
XBRL and
 
filed
herewith).
* Filed herewith
** These interactive data files are furnished and deemed not filed or part of a registration
statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, as
amended, are deemed not filed for purposes of Section 18 of the Securities Exchange Act of
1934, as amended, and otherwise are not subject to liability under those sections.
 
 
 
 
5
 
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly
caused this report to be signed on its behalf by the undersigned hereunto duly authorized.
 
CONOCOPHILLIPS
/s/
 
Catherine A. Brooks
 
Catherine A. Brooks
(Chief Accounting and Duly Authorized Officer)
November 16, 2020
 
 
 
Exhibit 23.1
 
Consent of Independent Registered Public Accounting Firm
 
 
We consent to the incorporation by reference in the following Registration Statements:
 
 
●
 
ConocoPhillips
 
Form S-3
 
File No. 333-240978
 
●
 
ConocoPhillips
 
Form S-4
 
File No. 333-130967
 
●
 
ConocoPhillips
 
Form S-8
 
File No. 333-98681
 
●
 
ConocoPhillips
 
Form S-8
 
File No. 333-116216
 
●
 
ConocoPhillips
 
Form S-8
 
File No. 333-133101
 
●
 
ConocoPhillips
 
Form S-8
 
File No. 333-159318
 
●
 
ConocoPhillips
 
Form S-8
 
File No. 333-171047
 
●
 
ConocoPhillips
 
Form S-8
 
File No. 333-174479
 
●
 
ConocoPhillips
 
Form S-8
 
File No. 333-196349
 
●
 
ConocoPhillips
 
Form S-8
 
File No. 333-130967
 
 
of our report dated February 18, 2020, except as it relates to the effects
 
of the change in segments
described in Note 25, as to which the date is November 16, 2020, with respect
 
to the consolidated
financial statements (including condensed consolidating
 
financial information and financial statement
schedule) of ConocoPhillips and our report dated February
 
18, 2020, with respect to the effectiveness of
internal control over financial reporting of ConocoPhillips, included in this
 
Current Report on Form 8-K.
 
 
/s/ Ernst & Young LLP
 
 
Houston, Texas
November 16, 2020
 
 
 
 
 
 
 
 
Exhibit 23.2
 
 
DeGolyer and MacNaughton
5001 Spring Valley Road
Suite 800 East
Dallas, Texas 75244
 
November 16, 2020
 
 
ConocoPhillips
 
925 N. Eldridge Parkway
Houston, Texas 77079
 
Ladies and Gentlemen:
We hereby consent to the use of the name DeGolyer and MacNaughton, to references to
 
DeGolyer and
MacNaughton as an independent petroleum engineering
 
consulting firm in ConocoPhillips’
 
Current Report on
Form 8-K Exhibit 99.1, with respect to the sections
 
under “Item 8. Financial Statements and Supplementary
Data” and subheading “Reserves Governance” and
 
under “Item 15. Exhibits, Financial
 
Statement Schedules”
and to the inclusion of our process review letter
 
report dated February 18, 2020 (our Report),
 
as exhibit 99.2
 
to ConocoPhillips’ Current Report on Form 8-K. We also consent to the incorporation
 
by reference of our
Report in the Registration Statements filed
 
by ConocoPhillips on Form S-3 (File No. 333-240978),
 
Form S-4
(File No. 333-130967), and Form S-8 (File Nos. 333-98681,
 
333-116216, 333-133101, 333-159318, 333-
171047, 333-174479, 333-196349, and 333-130967).
 
Very
 
truly yours,
/s/ DeGolyer and MacNaughton
 
DeGOLYER and MacNAUGHTON
 
Texas Registered Engineering Firm F-716
0.01 5 23 17 No 6 730 1 283 No No 998 us-gaap:DebtCurrent us-gaap:LongTermDebtAndCapitalLeaseObligations 0001163165 2018-01-01 2018-12-31 0001163165 2017-01-01 2017-12-31 0001163165 2019-01-01 2019-12-31 0001163165 2019-12-31 0001163165 2018-12-31 0001163165 us-gaap:RetainedEarningsMember 2017-01-01 2017-12-31 0001163165 us-gaap:NoncontrollingInterestMember 2017-01-01 2017-12-31 0001163165 us-gaap:AccumulatedOtherComprehensiveIncomeMember 2017-01-01 2017-12-31 0001163165 us-gaap:AdditionalPaidInCapitalMember 2017-01-01 2017-12-31 0001163165 us-gaap:CommonStockMember 2016-12-31 0001163165 us-gaap:AdditionalPaidInCapitalMember 2016-12-31 0001163165 us-gaap:TreasuryStockMember 2016-12-31 0001163165 us-gaap:AccumulatedOtherComprehensiveIncomeMember 2016-12-31 0001163165 us-gaap:RetainedEarningsMember 2016-12-31 0001163165 us-gaap:NoncontrollingInterestMember 2016-12-31 0001163165 2016-12-31 0001163165 us-gaap:CommonStockMember 2017-12-31 0001163165 us-gaap:AdditionalPaidInCapitalMember 2017-12-31 0001163165 us-gaap:TreasuryStockMember 2017-12-31 0001163165 us-gaap:AccumulatedOtherComprehensiveIncomeMember 2017-12-31 0001163165 us-gaap:RetainedEarningsMember 2017-12-31 0001163165 us-gaap:NoncontrollingInterestMember 2017-12-31 0001163165 us-gaap:RetainedEarningsMember 2018-01-01 2018-12-31 0001163165 us-gaap:NoncontrollingInterestMember 2018-01-01 2018-12-31 0001163165 us-gaap:AccumulatedOtherComprehensiveIncomeMember 2018-01-01 2018-12-31 0001163165 us-gaap:CommonStockMember 2018-12-31 0001163165 us-gaap:RetainedEarningsMember 2019-01-01 2019-12-31 0001163165 us-gaap:NoncontrollingInterestMember 2019-01-01 2019-12-31 0001163165 us-gaap:AdditionalPaidInCapitalMember 2019-01-01 2019-12-31 0001163165 us-gaap:CommonStockMember 2019-12-31 0001163165 us-gaap:AdditionalPaidInCapitalMember 2019-12-31 0001163165 us-gaap:TreasuryStockMember 2019-12-31 0001163165 us-gaap:AccumulatedOtherComprehensiveIncomeMember 2019-12-31 0001163165 us-gaap:RetainedEarningsMember 2019-12-31 0001163165 us-gaap:NoncontrollingInterestMember 2019-12-31 0001163165 2017-12-31 0001163165 us-gaap:AdditionalPaidInCapitalMember 2018-01-01 2018-12-31 0001163165 us-gaap:AccumulatedOtherComprehensiveIncomeMember 2019-01-01 2019-12-31 0001163165 us-gaap:ForeignCurrencyGainLossMember 2019-01-01 2019-12-31 0001163165 us-gaap:ForeignCurrencyGainLossMember 2018-01-01 2018-12-31 0001163165 us-gaap:ForeignCurrencyGainLossMember 2017-01-01 2017-12-31 0001163165 us-gaap:FairValueMeasurementsRecurringMember us-gaap:FairValueInputsLevel1Member 2019-12-31 0001163165 us-gaap:FairValueMeasurementsRecurringMember us-gaap:FairValueInputsLevel2Member 2019-12-31 0001163165 us-gaap:FairValueMeasurementsRecurringMember us-gaap:FairValueInputsLevel3Member 2019-12-31 0001163165 us-gaap:FairValueMeasurementsRecurringMember 2018-12-31 0001163165 us-gaap:FairValueMeasurementsRecurringMember 2019-12-31 0001163165 us-gaap:FairValueMeasurementsRecurringMember us-gaap:FairValueInputsLevel1Member 2018-12-31 0001163165 us-gaap:FairValueMeasurementsRecurringMember us-gaap:FairValueInputsLevel2Member 2018-12-31 0001163165 us-gaap:FairValueMeasurementsRecurringMember us-gaap:FairValueInputsLevel3Member 2018-12-31 0001163165 country:US 2019-12-31 0001163165 country:AU 2019-12-31 0001163165 country:CA 2019-12-31 0001163165 country:NO 2019-12-31 0001163165 country:GB 2019-12-31 0001163165 country:US 2018-12-31 0001163165 country:GB 2018-12-31 0001163165 country:AU 2018-12-31 0001163165 country:CA 2018-12-31 0001163165 country:NO 2018-12-31 0001163165 country:AU 2017-12-31 0001163165 country:NO 2017-12-31 0001163165 country:US 2017-12-31 0001163165 country:GB 2017-12-31 0001163165 country:CA 2017-12-31 0001163165 country:CN 2019-12-31 0001163165 country:ID 2019-12-31 0001163165 country:ID 2018-12-31 0001163165 country:CN 2018-12-31 0001163165 country:CN 2017-12-31 0001163165 country:ID 2017-12-31 0001163165 country:MY 2019-12-31 0001163165 country:MY 2018-12-31 0001163165 country:MY 2017-12-31 0001163165 us-gaap:PrepaidExpensesAndOtherCurrentAssetsMember 2019-12-31 0001163165 us-gaap:PrepaidExpensesAndOtherCurrentAssetsMember 2018-12-31 0001163165 cop:CleanupRemediationActivitiesMember 2019-12-31 0001163165 cop:CleanupRemediationActivitiesMember 2018-12-31 0001163165 cop:CorporateAndOtherEnvironmentalLiabilitiesMember 2019-12-31 0001163165 cop:CorporateAndOtherEnvironmentalLiabilitiesMember 2018-12-31 0001163165 cop:FederalComprehensiveEnvironmentalResponseCompensationAndLiabilityActOrSimilarStateLawsMember 2019-12-31 0001163165 cop:FederalComprehensiveEnvironmentalResponseCompensationAndLiabilityActOrSimilarStateLawsMember 2018-12-31 0001163165 us-gaap:GuaranteeTypeOtherMember 2019-12-31 0001163165 us-gaap:IndemnificationGuaranteeMember 2019-12-31 0001163165 us-gaap:CommodityContractMember us-gaap:PrepaidExpensesAndOtherCurrentAssetsMember 2019-12-31 0001163165 us-gaap:CommodityContractMember us-gaap:PrepaidExpensesAndOtherCurrentAssetsMember 2018-12-31 0001163165 us-gaap:CommodityContractMember us-gaap:OtherAssetsMember 2019-12-31 0001163165 us-gaap:CommodityContractMember us-gaap:OtherAssetsMember 2018-12-31 0001163165 us-gaap:CommodityContractMember cop:OtherAccrualsMember 2019-12-31 0001163165 us-gaap:CommodityContractMember cop:OtherAccrualsMember 2018-12-31 0001163165 us-gaap:CommodityContractMember us-gaap:OtherLiabilitiesMember 2019-12-31 0001163165 us-gaap:CommodityContractMember us-gaap:OtherLiabilitiesMember 2018-12-31 0001163165 us-gaap:PensionPlansDefinedBenefitMember country:US 2019-12-31 0001163165 us-gaap:PensionPlansDefinedBenefitMember country:US 2018-12-31 0001163165 us-gaap:ForeignPlanMember us-gaap:PensionPlansDefinedBenefitMember 2019-12-31 0001163165 us-gaap:ForeignPlanMember us-gaap:PensionPlansDefinedBenefitMember 2018-12-31 0001163165 us-gaap:OtherPostretirementBenefitPlansDefinedBenefitMember 2019-12-31 0001163165 us-gaap:OtherPostretirementBenefitPlansDefinedBenefitMember 2018-12-31 0001163165 us-gaap:PensionPlansDefinedBenefitMember country:US 2019-01-01 2019-12-31 0001163165 us-gaap:ForeignPlanMember us-gaap:PensionPlansDefinedBenefitMember 2019-01-01 2019-12-31 0001163165 us-gaap:PensionPlansDefinedBenefitMember country:US 2018-01-01 2018-12-31 0001163165 us-gaap:ForeignPlanMember us-gaap:PensionPlansDefinedBenefitMember 2018-01-01 2018-12-31 0001163165 us-gaap:OtherPostretirementBenefitPlansDefinedBenefitMember 2018-01-01 2018-12-31 0001163165 us-gaap:OtherPostretirementBenefitPlansDefinedBenefitMember 2019-01-01 2019-12-31 0001163165 us-gaap:PensionPlansDefinedBenefitMember country:US 2017-01-01 2017-12-31 0001163165 us-gaap:ForeignPlanMember us-gaap:PensionPlansDefinedBenefitMember 2017-01-01 2017-12-31 0001163165 us-gaap:OtherPostretirementBenefitPlansDefinedBenefitMember 2017-01-01 2017-12-31 0001163165 country:EC cop:BurlingtonResourcesIncVsTheRepublicOfEcuadorMember cop:BurlingtonResourcesIncMember 2017-02-01 2017-02-28 0001163165 us-gaap:CommodityContractMember us-gaap:SalesMember 2019-01-01 2019-12-31 0001163165 us-gaap:CommodityContractMember us-gaap:OtherIncomeMember 2019-01-01 2019-12-31 0001163165 us-gaap:CommodityContractMember us-gaap:CostOfSalesMember 2019-01-01 2019-12-31 0001163165 us-gaap:CommodityContractMember us-gaap:SalesMember 2018-01-01 2018-12-31 0001163165 us-gaap:CommodityContractMember us-gaap:OtherIncomeMember 2018-01-01 2018-12-31 0001163165 us-gaap:CommodityContractMember us-gaap:CostOfSalesMember 2018-01-01 2018-12-31 0001163165 us-gaap:CommodityContractMember us-gaap:SalesMember 2017-01-01 2017-12-31 0001163165 us-gaap:CommodityContractMember us-gaap:OtherIncomeMember 2017-01-01 2017-12-31 0001163165 us-gaap:CommodityContractMember us-gaap:CostOfSalesMember 2017-01-01 2017-12-31 0001163165 us-gaap:NondesignatedMember cop:SellUsDollarBuyBritishPoundMember 2019-12-31 0001163165 us-gaap:NondesignatedMember cop:SellUsDollarBuyBritishPoundMember 2018-12-31 0001163165 us-gaap:NondesignatedMember cop:SellBritishPoundBuyOtherCurrenciesMember 2019-12-31 0001163165 us-gaap:NondesignatedMember cop:SellBritishPoundBuyOtherCurrenciesMember 2018-12-31 0001163165 us-gaap:NondesignatedMember cop:SellCanadianDollarBuyUsDollarMember 2019-12-31 0001163165 us-gaap:NondesignatedMember cop:SellCanadianDollarBuyUsDollarMember 2018-12-31 0001163165 us-gaap:FairValueInputsLevel1Member 2018-12-31 0001163165 cop:TwentyFourteenOmnibusStockAndPerformanceIncentivePlanOfConocoPhillipsMember 2019-12-31 0001163165 us-gaap:OtherPostretirementBenefitPlansDefinedBenefitMember cop:TwentyFourteenOmnibusStockAndPerformanceIncentivePlanOfConocoPhillipsMember 2019-01-01 2019-12-31 0001163165 cop:AustraliaPacificLNGMember 2019-12-31 0001163165 country:EC cop:BurlingtonResourcesIncVsTheRepublicOfEcuadorMember cop:BurlingtonResourcesIncMember 2017-12-01 2017-12-31 0001163165 srt:ReportableLegalEntitiesMember cop:ConocoPhillipsCompanyMember 2019-01-01 2019-12-31 0001163165 srt:ReportableLegalEntitiesMember cop:BurlingtonResourcesLLCMember 2019-01-01 2019-12-31 0001163165 srt:NonGuarantorSubsidiariesMember srt:ReportableLegalEntitiesMember 2019-01-01 2019-12-31 0001163165 srt:ConsolidationEliminationsMember 2019-01-01 2019-12-31 0001163165 srt:ReportableLegalEntitiesMember cop:ConocoPhillipsCompanyMember 2018-01-01 2018-12-31 0001163165 srt:ReportableLegalEntitiesMember cop:BurlingtonResourcesLLCMember 2018-01-01 2018-12-31 0001163165 srt:NonGuarantorSubsidiariesMember srt:ReportableLegalEntitiesMember 2018-01-01 2018-12-31 0001163165 srt:ConsolidationEliminationsMember 2018-01-01 2018-12-31 0001163165 srt:ReportableLegalEntitiesMember cop:ConocoPhillipsCompanyMember 2017-01-01 2017-12-31 0001163165 srt:ReportableLegalEntitiesMember cop:BurlingtonResourcesLLCMember 2017-01-01 2017-12-31 0001163165 srt:NonGuarantorSubsidiariesMember srt:ReportableLegalEntitiesMember 2017-01-01 2017-12-31 0001163165 srt:ConsolidationEliminationsMember 2017-01-01 2017-12-31 0001163165 srt:ReportableLegalEntitiesMember cop:ConocoPhillipsCompanyMember 2019-12-31 0001163165 srt:ReportableLegalEntitiesMember cop:BurlingtonResourcesLLCMember 2019-12-31 0001163165 srt:NonGuarantorSubsidiariesMember srt:ReportableLegalEntitiesMember 2019-12-31 0001163165 srt:ConsolidationEliminationsMember 2019-12-31 0001163165 srt:ReportableLegalEntitiesMember cop:ConocoPhillipsCompanyMember 2018-12-31 0001163165 srt:ReportableLegalEntitiesMember cop:BurlingtonResourcesLLCMember 2018-12-31 0001163165 srt:NonGuarantorSubsidiariesMember srt:ReportableLegalEntitiesMember 2018-12-31 0001163165 srt:ConsolidationEliminationsMember 2018-12-31 0001163165 srt:ParentCompanyMember srt:ReportableLegalEntitiesMember 2019-01-01 2019-12-31 0001163165 cop:AustraliaPacificLNGMember cop:ExportImportBankOfUsMember 2012-12-31 0001163165 cop:AustraliaPacificLNGMember cop:ExportImportBankOfChinaMember 2012-12-31 0001163165 cop:AustraliaPacificLNGMember cop:AustralianAndInternationalCommercialBankSyndicateMember 2012-12-31 0001163165 cop:AustraliaPacificLNGMember 2012-12-31 0001163165 cop:AustraliaPacificLNGMember 2018-12-31 0001163165 cop:QatarLiquefiedGasCompanyLimitedThreeMember 2019-12-31 0001163165 cop:OtherforeigncountriesmemberMember 2019-12-31 0001163165 cop:OtherforeigncountriesmemberMember 2018-12-31 0001163165 cop:OtherforeigncountriesmemberMember 2017-12-31 0001163165 us-gaap:PensionPlansDefinedBenefitMember country:US 2017-12-31 0001163165 us-gaap:ForeignPlanMember us-gaap:PensionPlansDefinedBenefitMember 2017-12-31 0001163165 srt:ParentCompanyMember 2019-01-01 2019-12-31 0001163165 srt:ParentCompanyMember 2018-01-01 2018-12-31 0001163165 srt:ParentCompanyMember 2017-01-01 2017-12-31 0001163165 srt:ParentCompanyMember 2019-12-31 0001163165 srt:ParentCompanyMember 2018-12-31 0001163165 cop:AustraliaPacificLNGMember 2017-12-31 0001163165 us-gaap:RestrictedStockUnitsRSUMember us-gaap:SegmentDiscontinuedOperationsMember 2018-12-31 0001163165 us-gaap:RestrictedStockUnitsRSUMember us-gaap:SegmentDiscontinuedOperationsMember 2019-01-01 2019-12-31 0001163165 us-gaap:RestrictedStockUnitsRSUMember us-gaap:SegmentDiscontinuedOperationsMember 2019-12-31 0001163165 us-gaap:DebtInstrumentRedemptionPeriodFourMember us-gaap:UnsecuredDebtMember cop:NinePointOneTwoFiveNotesMember 2019-12-31 0001163165 us-gaap:DebtInstrumentRedemptionPeriodFourMember us-gaap:UnsecuredDebtMember cop:NinePointOneTwoFiveNotesMember 2018-12-31 0001163165 us-gaap:UnsecuredDebtMember cop:EightPointTwoPercentNotesMember cop:DebtInstrumentRedemptionPeriodEightMember 2019-12-31 0001163165 us-gaap:UnsecuredDebtMember cop:EightPointTwoPercentNotesMember cop:DebtInstrumentRedemptionPeriodEightMember 2018-12-31 0001163165 us-gaap:UnsecuredDebtMember cop:SevenPointNinePercentNotesMember cop:DebtInstrumentRedemptionPeriodThirtyMember 2019-12-31 0001163165 us-gaap:UnsecuredDebtMember cop:SevenPointNinePercentNotesMember cop:DebtInstrumentRedemptionPeriodThirtyMember 2018-12-31 0001163165 us-gaap:UnsecuredDebtMember cop:SevenPointTwoFivePercentNotesMember cop:DebtInstrumentRedemptionPeriodFourteenMember 2019-12-31 0001163165 us-gaap:UnsecuredDebtMember cop:SevenPointTwoFivePercentNotesMember cop:DebtInstrumentRedemptionPeriodFourteenMember 2018-12-31 0001163165 us-gaap:UnsecuredDebtMember cop:SixPointEightSevenFiveNotesMember cop:DebtInstrumentRedemptionPeriodNineMember 2019-12-31 0001163165 us-gaap:UnsecuredDebtMember cop:SixPointEightSevenFiveNotesMember cop:DebtInstrumentRedemptionPeriodNineMember 2018-12-31 0001163165 us-gaap:UnsecuredDebtMember cop:SixPointFivePercentNotesMember cop:DebtInstrumentRedemptionPeriodTwentyTwoMember 2019-12-31 0001163165 us-gaap:UnsecuredDebtMember cop:SixPointFivePercentNotesMember cop:DebtInstrumentRedemptionPeriodTwentyTwoMember 2018-12-31 0001163165 us-gaap:UnsecuredDebtMember cop:FivePointNineFiveOnePercentNotesMember cop:DebtInstrumentRedemptionPeriodTwentyMember 2019-12-31 0001163165 us-gaap:UnsecuredDebtMember cop:FivePointNineFiveOnePercentNotesMember cop:DebtInstrumentRedemptionPeriodTwentyMember 2018-12-31 0001163165 us-gaap:UnsecuredDebtMember cop:FivepointninefivepercentnotesmemberMember cop:DebtInstrumentRedemptionPeriodNineteenMember 2019-12-31 0001163165 us-gaap:UnsecuredDebtMember cop:FivepointninefivepercentnotesmemberMember cop:DebtInstrumentRedemptionPeriodNineteenMember 2018-12-31 0001163165 us-gaap:UnsecuredDebtMember cop:FourPointNiveFiveNotesMember cop:DebtInstrumentRedemptionPeriodNineMember 2019-12-31 0001163165 us-gaap:UnsecuredDebtMember cop:FourPointNiveFiveNotesMember cop:DebtInstrumentRedemptionPeriodNineMember 2018-12-31 0001163165 us-gaap:UnsecuredDebtMember cop:FourPointThreePercentNotesMember cop:DebtInstrumentRedemptionPeriodTwentysevenMember 2019-12-31 0001163165 us-gaap:UnsecuredDebtMember cop:FourPointThreePercentNotesMember cop:DebtInstrumentRedemptionPeriodTwentysevenMember 2018-12-31 0001163165 us-gaap:UnsecuredDebtMember cop:FourPointOneFivePercentNotesMember cop:DebtinstrumentRedemptionPeriodSeventeenMember 2019-12-31 0001163165 us-gaap:UnsecuredDebtMember cop:FourPointOneFivePercentNotesMember cop:DebtinstrumentRedemptionPeriodSeventeenMember 2018-12-31 0001163165 us-gaap:UnsecuredDebtMember cop:ThreePointThreeFivePercentNotesMember cop:DebtInstrumentRedemptionPeriodSevenMember 2019-12-31 0001163165 us-gaap:UnsecuredDebtMember cop:ThreePointThreeFivePercentNotesMember cop:DebtInstrumentRedemptionPeriodSevenMember 2018-12-31 0001163165 cop:MarineTerminalRevenueRefundingBondsMember cop:VariableRateDebtBondsMember cop:DebtInstrumentRedemptionPeriodFourteenMember 2019-12-31 0001163165 cop:MarineTerminalRevenueRefundingBondsMember cop:VariableRateDebtBondsMember cop:DebtInstrumentRedemptionPeriodFourteenMember 2018-12-31 0001163165 us-gaap:UnsecuredDebtMember cop:EightPointOneTwoFivePercentNotesMember cop:DebtInstrumentRedemptionPeriodThirteenMember 2019-12-31 0001163165 us-gaap:UnsecuredDebtMember cop:EightPointOneTwoFivePercentNotesMember cop:DebtInstrumentRedemptionPeriodThirteenMember 2018-12-31 0001163165 us-gaap:UnsecuredDebtMember cop:SevenPointSixFivePercentNotesMember cop:DebtInstrumentRedemptionPeriodSixMember 2019-12-31 0001163165 us-gaap:UnsecuredDebtMember cop:SevenPointSixFivePercentNotesMember cop:DebtInstrumentRedemptionPeriodSixMember 2018-12-31 0001163165 us-gaap:UnsecuredDebtMember cop:SevenPointThreeSevenFivePercentNotesMember cop:DebtInstrumentRedemptionPeriodTwelveMember 2019-12-31 0001163165 us-gaap:UnsecuredDebtMember cop:SevenPointThreeSevenFivePercentNotesMember cop:DebtInstrumentRedemptionPeriodTwelveMember 2018-12-31 0001163165 us-gaap:UnsecuredDebtMember cop:SevenPointTwoPercentNotesMember cop:DebtInstrumentRedemptionPeriodFourteenMember 2019-12-31 0001163165 us-gaap:UnsecuredDebtMember cop:SevenPointTwoPercentNotesMember cop:DebtInstrumentRedemptionPeriodFourteenMember 2018-12-31 0001163165 us-gaap:UnsecuredDebtMember cop:SevenPercentNotesMember cop:DebtInstrumentRedemptionPeriodTwelveMember 2019-12-31 0001163165 us-gaap:UnsecuredDebtMember cop:SevenPercentNotesMember cop:DebtInstrumentRedemptionPeriodTwelveMember 2018-12-31 0001163165 us-gaap:UnsecuredDebtMember cop:SixPointNiveFivePercentNotesMember cop:DebtInstrumentRedemptionPeriodTwelveMember 2019-12-31 0001163165 us-gaap:UnsecuredDebtMember cop:SixPointNiveFivePercentNotesMember cop:DebtInstrumentRedemptionPeriodTwelveMember 2018-12-31 0001163165 us-gaap:UnsecuredDebtMember cop:FivePointNinePercentNotesMember cop:DebtInstrumentRedemptionPeriodFifteenMember 2019-12-31 0001163165 us-gaap:UnsecuredDebtMember cop:FivePointNinePercentNotesMember cop:DebtInstrumentRedemptionPeriodFifteenMember 2018-12-31 0001163165 us-gaap:UnsecuredDebtMember cop:FivePointNinePercentNotesMember cop:DebtInstrumentRedemptionPeriodTwentyOneMember 2019-12-31 0001163165 us-gaap:UnsecuredDebtMember cop:FivePointNinePercentNotesMember cop:DebtInstrumentRedemptionPeriodTwentyOneMember 2018-12-31 0001163165 us-gaap:UnsecuredDebtMember cop:ThreePointThreeFivePercentNotesMember cop:DebtInstrumentRedemptionPeriodEightMember 2019-12-31 0001163165 us-gaap:UnsecuredDebtMember cop:ThreePointThreeFivePercentNotesMember cop:DebtInstrumentRedemptionPeriodEightMember 2018-12-31 0001163165 cop:ZeroPointSixFourToOnePointSevenFourPercentIndustrialDevelopmentBondsMember cop:VariableRateDebtBondsMember 2019-12-31 0001163165 cop:ZeroPointSixFourToOnePointSevenFourPercentIndustrialDevelopmentBondsMember cop:VariableRateDebtBondsMember 2018-12-31 0001163165 us-gaap:UnsecuredDebtMember cop:OtherDebtMember 2019-12-31 0001163165 us-gaap:UnsecuredDebtMember cop:OtherDebtMember 2018-12-31 0001163165 us-gaap:UnsecuredDebtMember cop:SevenPointEightPercentNotesMember cop:DebtInstrumentRedemptionPeriodTenMember 2019-12-31 0001163165 us-gaap:UnsecuredDebtMember cop:SevenPointEightPercentNotesMember cop:DebtInstrumentRedemptionPeriodTenMember 2018-12-31 0001163165 us-gaap:UnsecuredDebtMember cop:SevenPointFourPercentNotesMember cop:DebtInstrumentRedemptionPeriodFourteenMember 2019-12-31 0001163165 us-gaap:UnsecuredDebtMember cop:SevenPointFourPercentNotesMember cop:DebtInstrumentRedemptionPeriodFourteenMember 2018-12-31 0001163165 us-gaap:UnsecuredDebtMember cop:DebtInstrumentRedemptionPeriodTwentyNineMember cop:FivepointninefivepercentnotesmemberMember 2019-12-31 0001163165 us-gaap:UnsecuredDebtMember cop:DebtInstrumentRedemptionPeriodTwentyNineMember cop:FivepointninefivepercentnotesmemberMember 2018-12-31 0001163165 us-gaap:DebtInstrumentRedemptionPeriodFiveMember us-gaap:UnsecuredDebtMember cop:TwoPointFourPercentNotesMember 2019-12-31 0001163165 us-gaap:DebtInstrumentRedemptionPeriodFiveMember us-gaap:UnsecuredDebtMember cop:TwoPointFourPercentNotesMember 2018-12-31 0001163165 us-gaap:DebtInstrumentRedemptionPeriodOneMember cop:FloatingRateNotesMember cop:FloatingRateNoteOnePointTwoFourPercentToOnePointSevenFivePercentMember 2019-12-31 0001163165 us-gaap:DebtInstrumentRedemptionPeriodOneMember cop:FloatingRateNotesMember cop:FloatingRateNoteOnePointTwoFourPercentToOnePointSevenFivePercentMember 2018-12-31 0001163165 us-gaap:AdditionalPaidInCapitalMember 2018-12-31 0001163165 us-gaap:TreasuryStockMember 2018-12-31 0001163165 us-gaap:AccumulatedOtherComprehensiveIncomeMember 2018-12-31 0001163165 us-gaap:RetainedEarningsMember 2018-12-31 0001163165 us-gaap:NoncontrollingInterestMember 2018-12-31 0001163165 cop:OneToThreeYearFromCompletionOfDrillingMember 2019-12-31 0001163165 cop:FourToSixYearsFromCompletionOfDrillingMember 2019-12-31 0001163165 cop:SevenToTenYearsFromCompletionOfDrillingMember 2019-12-31 0001163165 cop:ProjectThirteenMember 2019-12-31 0001163165 cop:ProjectThreeMember 2019-12-31 0001163165 cop:ProjectSixteenMember 2019-12-31 0001163165 cop:ProjectElevenMember 2019-12-31 0001163165 cop:ProjectMiddleMagdalenaMember 2019-12-31 0001163165 cop:NarwhalTrendAlaskaMember 2019-12-31 0001163165 cop:ProjectkamunsueastMember 2019-12-31 0001163165 cop:Projectnc98LibyaMember 2019-12-31 0001163165 cop:Wl4MalaysiaMember 2019-12-31 0001163165 cop:OtherProjectsMember 2019-12-31 0001163165 cop:OtherAccrualsMember 2019-12-31 0001163165 cop:OtherAccrualsMember 2018-12-31 0001163165 us-gaap:OtherLiabilitiesMember 2019-12-31 0001163165 us-gaap:OtherLiabilitiesMember 2018-12-31 0001163165 cop:AustraliaPacificLNGMember cop:ExportImportBankOfChinaMember 2018-09-01 2018-09-30 0001163165 cop:FosterCreekChristinaLakeFcclMember 2017-05-17 0001163165 cop:OneToThreeYearFromCompletionOfDrillingMember cop:ProjectThirteenMember 2019-12-31 0001163165 cop:FourToSixYearsFromCompletionOfDrillingMember cop:ProjectThirteenMember 2019-12-31 0001163165 cop:SevenToTenYearsFromCompletionOfDrillingMember cop:ProjectThirteenMember 2019-12-31 0001163165 cop:OneToThreeYearFromCompletionOfDrillingMember cop:ProjectThreeMember 2019-12-31 0001163165 cop:FourToSixYearsFromCompletionOfDrillingMember cop:ProjectThreeMember 2019-12-31 0001163165 cop:SevenToTenYearsFromCompletionOfDrillingMember cop:ProjectThreeMember 2019-12-31 0001163165 cop:OneToThreeYearFromCompletionOfDrillingMember cop:ProjectSixteenMember 2019-12-31 0001163165 cop:FourToSixYearsFromCompletionOfDrillingMember cop:ProjectSixteenMember 2019-12-31 0001163165 cop:SevenToTenYearsFromCompletionOfDrillingMember cop:ProjectSixteenMember 2019-12-31 0001163165 cop:OneToThreeYearFromCompletionOfDrillingMember cop:ProjectElevenMember 2019-12-31 0001163165 cop:FourToSixYearsFromCompletionOfDrillingMember cop:ProjectElevenMember 2019-12-31 0001163165 cop:SevenToTenYearsFromCompletionOfDrillingMember cop:ProjectElevenMember 2019-12-31 0001163165 cop:OneToThreeYearFromCompletionOfDrillingMember cop:ProjectMiddleMagdalenaMember 2019-12-31 0001163165 cop:FourToSixYearsFromCompletionOfDrillingMember cop:ProjectMiddleMagdalenaMember 2019-12-31 0001163165 cop:SevenToTenYearsFromCompletionOfDrillingMember cop:ProjectMiddleMagdalenaMember 2019-12-31 0001163165 cop:OneToThreeYearFromCompletionOfDrillingMember cop:NarwhalTrendAlaskaMember 2019-12-31 0001163165 cop:FourToSixYearsFromCompletionOfDrillingMember cop:NarwhalTrendAlaskaMember 2019-12-31 0001163165 cop:SevenToTenYearsFromCompletionOfDrillingMember cop:NarwhalTrendAlaskaMember 2019-12-31 0001163165 cop:OneToThreeYearFromCompletionOfDrillingMember cop:ProjectkamunsueastMember 2019-12-31 0001163165 cop:FourToSixYearsFromCompletionOfDrillingMember cop:ProjectkamunsueastMember 2019-12-31 0001163165 cop:SevenToTenYearsFromCompletionOfDrillingMember cop:ProjectkamunsueastMember 2019-12-31 0001163165 cop:OneToThreeYearFromCompletionOfDrillingMember cop:Projectnc98LibyaMember 2019-12-31 0001163165 cop:FourToSixYearsFromCompletionOfDrillingMember cop:Projectnc98LibyaMember 2019-12-31 0001163165 cop:SevenToTenYearsFromCompletionOfDrillingMember cop:Projectnc98LibyaMember 2019-12-31 0001163165 cop:OneToThreeYearFromCompletionOfDrillingMember cop:Wl4MalaysiaMember 2019-12-31 0001163165 cop:FourToSixYearsFromCompletionOfDrillingMember cop:Wl4MalaysiaMember 2019-12-31 0001163165 cop:SevenToTenYearsFromCompletionOfDrillingMember cop:Wl4MalaysiaMember 2019-12-31 0001163165 cop:OneToThreeYearFromCompletionOfDrillingMember cop:OtherProjectsMember 2019-12-31 0001163165 cop:FourToSixYearsFromCompletionOfDrillingMember cop:OtherProjectsMember 2019-12-31 0001163165 cop:SevenToTenYearsFromCompletionOfDrillingMember cop:OtherProjectsMember 2019-12-31 0001163165 us-gaap:CommodityContractMember us-gaap:ShortMember cop:NaturalGasPowerAndCarbonDioxideEmissionsFlatPriceMember 2019-12-31 0001163165 us-gaap:CommodityContractMember us-gaap:ShortMember cop:NaturalGasPowerAndCarbonDioxideEmissionsBasisMember 2019-12-31 0001163165 us-gaap:CommodityContractMember us-gaap:ShortMember cop:NaturalGasPowerAndCarbonDioxideEmissionsFlatPriceMember 2018-12-31 0001163165 cop:InEventOfLoweredCreditRatingMember 2019-12-31 0001163165 cop:InEventOfLoweredCreditRatingMember 2018-12-31 0001163165 cop:IneventOfDownGradeBelowInvestmentGradeMember 2019-12-31 0001163165 us-gaap:ShippingAndHandlingMember 2019-01-01 2019-12-31 0001163165 us-gaap:ShippingAndHandlingMember 2018-01-01 2018-12-31 0001163165 us-gaap:ShippingAndHandlingMember 2017-01-01 2017-12-31 0001163165 srt:AffiliatedEntityMember 2019-01-01 2019-12-31 0001163165 srt:AffiliatedEntityMember 2018-01-01 2018-12-31 0001163165 srt:AffiliatedEntityMember 2017-01-01 2017-12-31 0001163165 country:US 2019-01-01 2019-12-31 0001163165 country:US 2018-01-01 2018-12-31 0001163165 country:US 2017-01-01 2017-12-31 0001163165 country:AU 2019-01-01 2019-12-31 0001163165 country:AU 2018-01-01 2018-12-31 0001163165 country:AU 2017-01-01 2017-12-31 0001163165 country:CA 2019-01-01 2019-12-31 0001163165 country:CA 2018-01-01 2018-12-31 0001163165 country:CA 2017-01-01 2017-12-31 0001163165 country:CN 2019-01-01 2019-12-31 0001163165 country:CN 2018-01-01 2018-12-31 0001163165 country:CN 2017-01-01 2017-12-31 0001163165 country:ID 2019-01-01 2019-12-31 0001163165 country:ID 2018-01-01 2018-12-31 0001163165 country:ID 2017-01-01 2017-12-31 0001163165 country:LY 2019-01-01 2019-12-31 0001163165 country:LY 2018-01-01 2018-12-31 0001163165 country:LY 2017-01-01 2017-12-31 0001163165 country:MY 2019-01-01 2019-12-31 0001163165 country:MY 2018-01-01 2018-12-31 0001163165 country:MY 2017-01-01 2017-12-31 0001163165 country:NO 2019-01-01 2019-12-31 0001163165 country:NO 2018-01-01 2018-12-31 0001163165 country:NO 2017-01-01 2017-12-31 0001163165 country:GB 2019-01-01 2019-12-31 0001163165 country:GB 2018-01-01 2018-12-31 0001163165 country:GB 2017-01-01 2017-12-31 0001163165 cop:OtherforeigncountriesmemberMember 2019-01-01 2019-12-31 0001163165 cop:OtherforeigncountriesmemberMember 2018-01-01 2018-12-31 0001163165 cop:OtherforeigncountriesmemberMember 2017-01-01 2017-12-31 0001163165 country:LY 2019-12-31 0001163165 country:LY 2018-12-31 0001163165 country:LY 2017-12-31 0001163165 srt:NaturalGasReservesMember 2019-01-01 2019-12-31 0001163165 srt:NaturalGasReservesMember 2018-01-01 2018-12-31 0001163165 srt:NaturalGasReservesMember 2017-01-01 2017-12-31 0001163165 srt:NaturalGasLiquidsReservesMember 2019-01-01 2019-12-31 0001163165 srt:NaturalGasLiquidsReservesMember 2018-01-01 2018-12-31 0001163165 srt:NaturalGasLiquidsReservesMember 2017-01-01 2017-12-31 0001163165 us-gaap:EmployeeStockOptionMember cop:TwentyFourteenOmnibusStockAndPerformanceIncentivePlanOfConocoPhillipsMember 2019-01-01 2019-12-31 0001163165 us-gaap:RestrictedStockUnitsRSUMember cop:TwentyFourteenOmnibusStockAndPerformanceIncentivePlanOfConocoPhillipsMember 2019-01-01 2019-12-31 0001163165 cop:BurlingtonResourcesIncVsTheRepublicOfEcuadorMember 2018-01-01 2018-12-31 0001163165 cop:FosterCreekChristinaLakeAndWesternCanadaGasPropertiesMember 2017-01-01 2017-12-31 0001163165 cop:FinancialDerivativeContractsMember 2019-01-01 2019-12-31 0001163165 cop:FinancialDerivativeContractsMember 2018-01-01 2018-12-31 0001163165 cop:FinancialDerivativeContractsMember 2017-01-01 2017-12-31 0001163165 cop:RSUCashSettledMember 2018-12-31 0001163165 cop:RSUCashSettledMember 2019-12-31 0001163165 cop:RSUStockSettledShareMember 2019-12-31 0001163165 cop:PSUStockSettledMember 2018-12-31 0001163165 cop:PSUStockSettledMember 2019-01-01 2019-12-31 0001163165 cop:PSUCashSettledProgramMember 2019-12-31 0001163165 cop:PSUCashSettledProgramMember 2019-01-01 2019-12-31 0001163165 us-gaap:PensionPlansDefinedBenefitMember us-gaap:QualifiedPlanMember country:US cop:PrudentialBenefitObligationMember 2018-01-01 2018-12-31 0001163165 us-gaap:AccountingStandardsUpdate201409Member 2019-01-01 2019-12-31 0001163165 us-gaap:AccountingStandardsUpdate201409Member 2018-01-01 2018-12-31 0001163165 us-gaap:AccountingStandardsUpdate201409Member 2017-01-01 2017-12-31 0001163165 cop:PhysicalGasContractsMember 2019-01-01 2019-12-31 0001163165 cop:PhysicalGasContractsMember 2018-01-01 2018-12-31 0001163165 cop:PhysicalGasContractsMember 2017-01-01 2017-12-31 0001163165 cop:CrudeOilProductLineMember 2019-01-01 2019-12-31 0001163165 cop:CrudeOilProductLineMember 2018-01-01 2018-12-31 0001163165 cop:CrudeOilProductLineMember 2017-01-01 2017-12-31 0001163165 cop:NaturalGasProductLineMember 2019-01-01 2019-12-31 0001163165 cop:NaturalGasProductLineMember 2018-01-01 2018-12-31 0001163165 cop:NaturalGasProductLineMember 2017-01-01 2017-12-31 0001163165 cop:OtherProductsMember 2019-01-01 2019-12-31 0001163165 cop:OtherProductsMember 2018-01-01 2018-12-31 0001163165 cop:OtherProductsMember 2017-01-01 2017-12-31 0001163165 cop:RSUCashSettledMember 2019-01-01 2019-12-31 0001163165 cop:RSUStockSettledShareMember 2018-12-31 0001163165 cop:RSUStockSettledShareMember 2019-01-01 2019-12-31 0001163165 cop:PSUStockSettledMember 2019-12-31 0001163165 cop:PSUCashSettledProgramMember 2018-12-31 0001163165 cop:ClairFieldMember 2018-01-01 2018-12-31 0001163165 country:VE cop:ConocoPhillipsVsPetroleosDeVenezuelaSAMember 2019-01-01 2019-12-31 0001163165 cop:RSUStockSettledShareMember cop:TwentyFourteenOmnibusStockAndPerformanceIncentivePlanOfConocoPhillipsMember 2019-01-01 2019-12-31 0001163165 cop:TwentyFourteenOmnibusStockAndPerformanceIncentivePlanOfConocoPhillipsMember cop:PSUStockSettledMember 2019-01-01 2019-12-31 0001163165 cop:TwentyFourteenOmnibusStockAndPerformanceIncentivePlanOfConocoPhillipsMember cop:PSUCashSettledProgramMember 2019-01-01 2019-12-31 0001163165 us-gaap:CarryingReportedAmountFairValueDisclosureMember 2019-12-31 0001163165 us-gaap:CarryingReportedAmountFairValueDisclosureMember 2018-12-31 0001163165 us-gaap:CarryingReportedAmountFairValueDisclosureMember us-gaap:CommodityContractMember 2019-12-31 0001163165 us-gaap:CarryingReportedAmountFairValueDisclosureMember us-gaap:CommodityContractMember 2018-12-31 0001163165 cop:VariableRateDebtBondsMember 2019-12-31 0001163165 us-gaap:OtherPostretirementBenefitPlansDefinedBenefitMember 2017-12-31 0001163165 cop:RSUCashSettledMember cop:TwentyFourteenOmnibusStockAndPerformanceIncentivePlanOfConocoPhillipsMember 2019-01-01 2019-12-31 0001163165 srt:ConsolidationEliminationsMember 2016-12-31 0001163165 srt:ParentCompanyMember 2017-12-31 0001163165 srt:ReportableLegalEntitiesMember cop:ConocoPhillipsCompanyMember 2017-12-31 0001163165 srt:ReportableLegalEntitiesMember cop:BurlingtonResourcesLLCMember 2017-12-31 0001163165 srt:NonGuarantorSubsidiariesMember srt:ReportableLegalEntitiesMember 2017-12-31 0001163165 srt:ParentCompanyMember srt:RestatementAdjustmentMember 2018-12-31 0001163165 srt:ReportableLegalEntitiesMember srt:RestatementAdjustmentMember cop:ConocoPhillipsCompanyMember 2018-12-31 0001163165 srt:ReportableLegalEntitiesMember srt:RestatementAdjustmentMember cop:BurlingtonResourcesLLCMember 2018-12-31 0001163165 srt:NonGuarantorSubsidiariesMember srt:ReportableLegalEntitiesMember srt:RestatementAdjustmentMember 2018-12-31 0001163165 srt:ReportableLegalEntitiesMember cop:BurlingtonResourcesLLCMember 2016-12-31 0001163165 srt:NonGuarantorSubsidiariesMember srt:ReportableLegalEntitiesMember 2016-12-31 0001163165 srt:ConsolidationEliminationsMember 2017-12-31 0001163165 srt:ConsolidationEliminationsMember srt:RestatementAdjustmentMember 2018-12-31 0001163165 us-gaap:CorporateNonSegmentMember 2019-01-01 2019-12-31 0001163165 us-gaap:CorporateNonSegmentMember 2018-01-01 2018-12-31 0001163165 us-gaap:CorporateNonSegmentMember 2017-01-01 2017-12-31 0001163165 us-gaap:CorporateNonSegmentMember 2019-12-31 0001163165 us-gaap:CorporateNonSegmentMember 2018-12-31 0001163165 us-gaap:CorporateNonSegmentMember 2017-12-31 0001163165 us-gaap:TreasuryStockMember 2018-01-01 2018-12-31 0001163165 us-gaap:TreasuryStockMember 2017-01-01 2017-12-31 0001163165 us-gaap:TreasuryStockMember 2019-01-01 2019-12-31 0001163165 cop:ConocoPhillipsCompanyMember 2017-01-01 2017-12-31 0001163165 us-gaap:CoVenturerMember 2019-01-01 2019-12-31 0001163165 us-gaap:CoVenturerMember 2018-12-31 0001163165 srt:RestatementAdjustmentMember 2017-12-31 0001163165 us-gaap:QualifiedPlanMember 2019-12-31 0001163165 us-gaap:NonqualifiedPlanMember us-gaap:UnfundedPlanMember 2019-12-31 0001163165 us-gaap:PensionPlansDefinedBenefitMember us-gaap:QualifiedPlanMember country:US 2019-01-01 2019-12-31 0001163165 us-gaap:PensionPlansDefinedBenefitMember us-gaap:QualifiedPlanMember country:US 2018-01-01 2018-12-31 0001163165 us-gaap:PensionPlansDefinedBenefitMember us-gaap:QualifiedPlanMember country:US 2017-01-01 2017-12-31 0001163165 us-gaap:QualifiedPlanMember 2018-12-31 0001163165 us-gaap:NonqualifiedPlanMember us-gaap:UnfundedPlanMember 2018-12-31 0001163165 us-gaap:AccountingStandardsUpdate201802Member srt:ScenarioPreviouslyReportedMember 2018-12-31 0001163165 us-gaap:AccountingStandardsUpdate201802Member 2018-12-31 0001163165 cop:MwccMember cop:MwccMember 2019-12-31 0001163165 cop:MwccMember cop:MwccMember 2019-06-30 0001163165 us-gaap:AccountingStandardsUpdate201802Member srt:RestatementAdjustmentMember 2018-12-31 0001163165 cop:MwccMember cop:MwccMember 2019-04-01 2019-06-30 0001163165 us-gaap:OtherPostretirementBenefitPlansDefinedBenefitMember country:US cop:CopPreSixtyFiveRetireeMember 2019-12-31 0001163165 us-gaap:OtherPostretirementBenefitPlansDefinedBenefitMember country:US cop:PostSixtyFiveRetireeMember 2019-12-31 0001163165 us-gaap:DefinedBenefitPlanEquitySecuritiesMember 2019-12-31 0001163165 us-gaap:DefinedBenefitPlanDebtSecurityMember 2019-12-31 0001163165 us-gaap:InsuranceContractRightsAndObligationsFairValueOptionMember 2019-12-31 0001163165 us-gaap:DefinedBenefitPlanRealEstateMember 2019-12-31 0001163165 us-gaap:InsuranceContractRightsAndObligationsFairValueOptionMember 2018-12-31 0001163165 us-gaap:OtherInvestmentsMember 2019-12-31 0001163165 us-gaap:ForeignPlanMember us-gaap:RetirementPlanTaxStatusDomain 2019-12-31 0001163165 us-gaap:EmployeeSeveranceMember 2019-01-01 2019-12-31 0001163165 us-gaap:EmployeeSeveranceMember 2019-12-31 0001163165 us-gaap:EmployeeSeveranceMember 2018-12-31 0001163165 us-gaap:EmployeeSeveranceMember cop:ShortTermSupplementalUnemploymentBenefitsMember 2019-12-31 0001163165 cop:RSUStockSettledShareMember 2017-01-01 2017-12-31 0001163165 cop:PSUStockSettledMember 2018-01-01 2018-12-31 0001163165 cop:PSUStockSettledMember 2017-01-01 2017-12-31 0001163165 cop:AustraliaPacificLNGMember cop:FinanceReserveGuaranteeMember 2019-12-31 0001163165 cop:AustraliaPacificLNGMember cop:FinanceReserveGuaranteeMember 2019-01-01 2019-12-31 0001163165 cop:AustraliaPacificLNGMember cop:ContinuedDevelopmentMember 2019-12-31 0001163165 us-gaap:GuaranteeTypeOtherMember 2019-01-01 2019-12-31 0001163165 us-gaap:CommodityContractMember us-gaap:ShortMember cop:NaturalGasPowerAndCarbonDioxideEmissionsBasisMember 2018-12-31 0001163165 us-gaap:NondesignatedMember cop:BuyBritishPoundSellEuroMember 2018-12-31 0001163165 us-gaap:BankTimeDepositsMember cop:RemainingMaturities1To90DaysMemberMember 2019-12-31 0001163165 us-gaap:BankTimeDepositsMember cop:RemainingMaturities1To90DaysMemberMember 2018-12-31 0001163165 us-gaap:BankTimeDepositsMember cop:RemainingMaturities91To180DaysMember 2019-12-31 0001163165 us-gaap:BankTimeDepositsMember cop:RemainingMaturities91To180DaysMember 2018-12-31 0001163165 us-gaap:CommercialPaperMember cop:RemainingMaturities1To90DaysMemberMember 2019-12-31 0001163165 us-gaap:CommercialPaperMember cop:RemainingMaturities1To90DaysMemberMember 2018-12-31 0001163165 us-gaap:CommonStockMember cop:CenovusEnergyMember 2019-12-31 0001163165 us-gaap:FairValueMeasurementsNonrecurringMember 2019-11-01 2019-11-30 0001163165 us-gaap:FairValueMeasurementsNonrecurringMember 2019-10-01 2019-12-31 0001163165 us-gaap:FairValueMeasurementsNonrecurringMember us-gaap:FairValueInputsLevel1Member 2019-03-31 0001163165 us-gaap:FairValueMeasurementsNonrecurringMember us-gaap:FairValueInputsLevel2Member 2019-03-31 0001163165 us-gaap:FairValueMeasurementsNonrecurringMember us-gaap:FairValueInputsLevel3Member 2019-03-31 0001163165 us-gaap:FairValueMeasurementsNonrecurringMember us-gaap:FairValueInputsLevel1Member 2019-05-31 0001163165 us-gaap:FairValueMeasurementsNonrecurringMember us-gaap:FairValueInputsLevel2Member 2019-05-31 0001163165 us-gaap:FairValueMeasurementsNonrecurringMember us-gaap:FairValueInputsLevel3Member 2019-05-31 0001163165 us-gaap:EstimateOfFairValueFairValueDisclosureMember 2019-12-31 0001163165 us-gaap:EstimateOfFairValueFairValueDisclosureMember 2018-12-18 0001163165 us-gaap:CommodityContractMember us-gaap:EstimateOfFairValueFairValueDisclosureMember 2019-12-31 0001163165 us-gaap:CommodityContractMember us-gaap:EstimateOfFairValueFairValueDisclosureMember 2018-12-18 0001163165 srt:ScenarioPreviouslyReportedMember 2018-12-31 0001163165 us-gaap:ForeignPlanMember 2017-01-01 2017-12-31 0001163165 us-gaap:EmployeeStockOptionMember cop:TwentyFourteenOmnibusStockAndPerformanceIncentivePlanOfConocoPhillipsMember 2017-01-01 2017-12-31 0001163165 us-gaap:EmployeeStockOptionMember cop:TwentyFourteenOmnibusStockAndPerformanceIncentivePlanOfConocoPhillipsMember 2018-01-01 2018-12-31 0001163165 cop:AustraliaPacificLNGMember cop:GuaranteeNaturalGasDeliveryMember 2019-12-31 0001163165 cop:AustraliaPacificLNGMember cop:GuaranteeNaturalGasDeliveryMember 2019-01-01 2019-12-31 0001163165 us-gaap:NondesignatedMember cop:BuyBritishPoundSellEuroMember 2019-12-31 0001163165 us-gaap:USGovernmentDebtSecuritiesMember cop:RemainingMaturities1To90DaysMemberMember 2019-12-31 0001163165 us-gaap:USGovernmentDebtSecuritiesMember cop:RemainingMaturities1To90DaysMemberMember 2018-12-31 0001163165 us-gaap:CorporateDebtSecuritiesMember 2019-12-31 0001163165 us-gaap:CommercialPaperMember 2019-12-31 0001163165 us-gaap:USGovernmentDebtSecuritiesMember 2019-12-31 0001163165 us-gaap:AssetBackedSecuritiesMember 2019-12-31 0001163165 us-gaap:ForeignPlanMember 2019-01-01 2019-12-31 0001163165 us-gaap:ForeignPlanMember 2018-01-01 2018-12-31 0001163165 cop:RSUStockSettledShareMember 2018-01-01 2018-12-31 0001163165 cop:RSUCashSettledMember 2018-01-01 2018-12-31 0001163165 srt:NonGuarantorSubsidiariesMember srt:ReportableLegalEntitiesMember srt:RestatementAdjustmentMember 2017-12-31 0001163165 cop:AustraliaPacificLNGMember cop:MaxPotentialFuturePaymentsRecklessBreachMember 2019-12-31 0001163165 cop:AustraliaPacificLNGMember cop:ContinuedDevelopmentMember 2019-01-01 2019-12-31 0001163165 us-gaap:GuaranteeTypeOtherMember cop:UKSubsidiariesMember 2019-12-31 0001163165 us-gaap:DemandDepositsMember 2019-12-31 0001163165 us-gaap:DemandDepositsMember 2018-12-31 0001163165 us-gaap:FairValueMeasurementsNonrecurringMember 2019-11-30 0001163165 us-gaap:FairValueMeasurementsNonrecurringMember 2019-12-31 0001163165 us-gaap:FairValueMeasurementsNonrecurringMember 2019-01-01 2019-03-31 0001163165 us-gaap:FairValueMeasurementsNonrecurringMember 2019-05-01 2019-05-31 0001163165 us-gaap:FairValueMeasurementsNonrecurringMember 2018-03-31 0001163165 us-gaap:FairValueMeasurementsNonrecurringMember us-gaap:FairValueInputsLevel1Member 2018-03-31 0001163165 us-gaap:FairValueMeasurementsNonrecurringMember us-gaap:FairValueInputsLevel2Member 2018-03-31 0001163165 us-gaap:FairValueMeasurementsNonrecurringMember us-gaap:FairValueInputsLevel3Member 2018-03-31 0001163165 us-gaap:FairValueMeasurementsNonrecurringMember 2018-09-30 0001163165 us-gaap:FairValueMeasurementsNonrecurringMember us-gaap:FairValueInputsLevel1Member 2018-09-30 0001163165 us-gaap:FairValueMeasurementsNonrecurringMember us-gaap:FairValueInputsLevel2Member 2018-09-30 0001163165 us-gaap:FairValueMeasurementsNonrecurringMember us-gaap:FairValueInputsLevel3Member 2018-09-30 0001163165 us-gaap:FairValueMeasurementsNonrecurringMember 2018-01-01 2018-03-31 0001163165 us-gaap:FairValueMeasurementsNonrecurringMember 2018-07-01 2018-09-30 0001163165 2020-02-01 0001163165 us-gaap:AccountingStandardsUpdate201602Member srt:RestatementAdjustmentMember 2018-12-31 0001163165 us-gaap:RevolvingCreditFacilityMember 2019-12-31 0001163165 us-gaap:FairValueMeasurementsNonrecurringMember us-gaap:FairValueInputsLevel1Member 2019-11-30 0001163165 us-gaap:FairValueMeasurementsNonrecurringMember us-gaap:FairValueInputsLevel2Member 2019-11-30 0001163165 us-gaap:FairValueMeasurementsNonrecurringMember us-gaap:FairValueInputsLevel3Member 2019-11-30 0001163165 us-gaap:FairValueMeasurementsNonrecurringMember us-gaap:FairValueInputsLevel1Member 2019-12-31 0001163165 us-gaap:FairValueMeasurementsNonrecurringMember us-gaap:FairValueInputsLevel2Member 2019-12-31 0001163165 us-gaap:FairValueMeasurementsNonrecurringMember us-gaap:FairValueInputsLevel3Member 2019-12-31 0001163165 us-gaap:FairValueMeasurementsNonrecurringMember 2019-03-31 0001163165 us-gaap:FairValueMeasurementsNonrecurringMember 2019-05-31 0001163165 us-gaap:CarryingReportedAmountFairValueDisclosureMember 2018-12-18 0001163165 2016-11-30 2019-12-31 0001163165 us-gaap:AccountingStandardsUpdate201602Member 2019-12-31 0001163165 cop:VariableRateDebtBondsMember 2018-12-31 0001163165 us-gaap:RevolvingCreditFacilityMember 2019-01-01 2019-12-31 0001163165 us-gaap:LetterOfCreditMember 2019-12-31 0001163165 cop:AustraliaPacificLNGMember 2019-12-31 0001163165 us-gaap:OtherLongTermInvestmentsMember 2019-12-31 0001163165 cop:AustraliaPacificLNGMember cop:OriginEnergyMember 2019-12-31 0001163165 cop:AustraliaPacificLNGMember cop:ChinaPetrochemicalCorporationSinopecMember 2019-12-31 0001163165 cop:MwccMember 2019-12-31 0001163165 cop:QatarLiquefiedGasCompanyLimitedThreeMember cop:MitsuiandcompanyMember 2019-12-31 0001163165 srt:CrudeOilMember 2019-01-01 2019-12-31 0001163165 srt:CrudeOilMember 2018-01-01 2018-12-31 0001163165 srt:CrudeOilMember 2017-01-01 2017-12-31 0001163165 cop:OtherProductsMember 2019-01-01 2019-12-31 0001163165 cop:OtherProductsMember 2018-01-01 2018-12-31 0001163165 cop:OtherProductsMember 2017-01-01 2017-12-31 0001163165 us-gaap:OtherLongTermInvestmentsMember 2018-12-31 0001163165 cop:QatarLiquefiedGasCompanyLimitedThreeMember cop:QatarPetroleumMember 2019-12-31 0001163165 cop:AustraliaPacificLNGMember 2019-01-01 2019-12-31 0001163165 cop:AustraliaPacificLNGMember cop:CommericalBanksMember 2019-03-31 0001163165 cop:AustraliaPacificLNGMember cop:CommericalBanksMember 2019-01-01 2019-12-31 0001163165 cop:AustraliaPacificLNGMember cop:UsprivateplacementbondtwomemberMember 2019-03-31 0001163165 cop:AustraliaPacificLNGMember cop:UsprivateplacementbondtwomemberMember 2019-01-01 2019-12-31 0001163165 cop:AustraliaPacificLNGMember cop:AustralianAndInternationalCommercialBankSyndicateMember 2019-01-01 2019-03-31 0001163165 cop:AustraliaPacificLNGMember 2017-04-01 2017-06-30 0001163165 cop:QatarLiquefiedGasCompanyLimitedThreeMember cop:CreditAgenciesMember 2019-12-31 0001163165 cop:QatarLiquefiedGasCompanyLimitedThreeMember 2019-01-01 2019-12-31 0001163165 us-gaap:AccountingStandardsUpdate201802Member 2019-01-01 2019-12-31 0001163165 cop:AustraliaPacificLNGMember cop:USPrivatePlacementBondMember 2018-09-30 0001163165 cop:AustraliaPacificLNGMember 2019-03-31 0001163165 srt:ParentCompanyMember cop:QatarLiquefiedGasCompanyLimitedThreeMember 2019-12-31 0001163165 us-gaap:AccountingStandardsUpdate201601Member srt:RestatementAdjustmentMember 2018-01-01 2018-12-31 0001163165 us-gaap:CoVenturerMember us-gaap:PropertyPlantAndEquipmentMember 2019-12-31 0001163165 cop:ConocoPhillipsVsPetroleosDeVenezuelaSAMember 2019-01-01 2019-12-31 0001163165 cop:ConocoPhillipsVsPetroleosDeVenezuelaSAMember 2018-01-01 2018-12-31 0001163165 cop:AustraliaPacificLNGMember cop:ExportImportBankOfChinaMember 2019-01-01 2019-12-31 0001163165 cop:AustraliaPacificLNGMember cop:ExportImportBankOfChinaMember 2019-01-01 2019-03-31 0001163165 cop:QatarLiquefiedGasCompanyLimitedThreeMember cop:CommericalBanksMember 2019-12-31 0001163165 us-gaap:CurrencySwapMember 2017-01-01 2017-12-31 0001163165 us-gaap:CoVenturerMember 2019-12-31 0001163165 cop:BurlingtonResourcesIncVsTheRepublicOfEcuadorMember 2017-01-01 2017-12-31 0001163165 country:VE cop:ConocoPhillipsVsPetroleosDeVenezuelaSAMember 2019-08-29 0001163165 country:VE cop:ConocoPhillipsVersusPetroleosDeVenezuela2Member 2019-01-01 2019-12-31 0001163165 country:VE cop:ConocoPhillipsVersusPetroleosDeVenezuela3Member 2019-08-01 2019-08-31 0001163165 country:VE cop:ConocoPhillipsVsPetroleosDeVenezuelaSAMember 2019-03-01 2019-03-31 0001163165 country:VE cop:ConocoPhillipsVersusPetroleosDeVenezuela2Member 2018-04-01 2018-04-30 0001163165 country:EC cop:BurlingtonResourcesIncVsTheRepublicOfEcuadorMember cop:BurlingtonResourcesIncMember 2018-04-01 2018-04-30 0001163165 us-gaap:RestrictedStockUnitsRSUMember us-gaap:SegmentDiscontinuedOperationsMember 2017-01-01 2017-12-31 0001163165 us-gaap:RestrictedStockUnitsRSUMember us-gaap:SegmentDiscontinuedOperationsMember 2018-01-01 2018-12-31 0001163165 cop:PSUCashSettledProgramMember 2018-01-01 2018-12-31 0001163165 us-gaap:OperatingSegmentsMember cop:LowerFortyEightSegmentMember 2019-01-01 2019-12-31 0001163165 us-gaap:OperatingSegmentsMember cop:LowerFortyEightSegmentMember 2018-01-01 2018-12-31 0001163165 us-gaap:OperatingSegmentsMember cop:LowerFortyEightSegmentMember 2017-01-01 2017-12-31 0001163165 us-gaap:IntersegmentEliminationMember cop:LowerFortyEightSegmentMember 2019-01-01 2019-12-31 0001163165 us-gaap:IntersegmentEliminationMember cop:LowerFortyEightSegmentMember 2018-01-01 2018-12-31 0001163165 us-gaap:IntersegmentEliminationMember cop:LowerFortyEightSegmentMember 2017-01-01 2017-12-31 0001163165 cop:LowerFortyEightSegmentMember 2019-01-01 2019-12-31 0001163165 cop:LowerFortyEightSegmentMember 2018-01-01 2018-12-31 0001163165 cop:LowerFortyEightSegmentMember 2017-01-01 2017-12-31 0001163165 us-gaap:OperatingSegmentsMember 2019-01-01 2019-12-31 0001163165 us-gaap:OperatingSegmentsMember 2018-01-01 2018-12-31 0001163165 us-gaap:OperatingSegmentsMember 2017-01-01 2017-12-31 0001163165 us-gaap:OperatingSegmentsMember cop:AlaskaSegmentMember 2019-12-31 0001163165 us-gaap:OperatingSegmentsMember cop:AlaskaSegmentMember 2018-12-18 0001163165 us-gaap:OperatingSegmentsMember cop:AlaskaSegmentMember 2017-12-31 0001163165 us-gaap:OperatingSegmentsMember cop:LowerFortyEightSegmentMember 2019-12-31 0001163165 us-gaap:OperatingSegmentsMember cop:LowerFortyEightSegmentMember 2018-12-18 0001163165 us-gaap:OperatingSegmentsMember cop:LowerFortyEightSegmentMember 2017-12-31 0001163165 us-gaap:OperatingSegmentsMember cop:CanadaSegmentMember 2019-12-31 0001163165 us-gaap:OperatingSegmentsMember cop:CanadaSegmentMember 2018-12-18 0001163165 us-gaap:OperatingSegmentsMember cop:CanadaSegmentMember 2017-12-31 0001163165 us-gaap:OperatingSegmentsMember cop:EuropeMiddleEastAndNorthAfricaSegmentMember 2019-12-31 0001163165 us-gaap:OperatingSegmentsMember cop:EuropeMiddleEastAndNorthAfricaSegmentMember 2018-12-18 0001163165 us-gaap:OperatingSegmentsMember cop:EuropeMiddleEastAndNorthAfricaSegmentMember 2017-12-31 0001163165 us-gaap:OperatingSegmentsMember srt:AsiaPacificMember 2019-12-31 0001163165 us-gaap:OperatingSegmentsMember srt:AsiaPacificMember 2018-12-18 0001163165 us-gaap:OperatingSegmentsMember srt:AsiaPacificMember 2017-12-31 0001163165 us-gaap:OperatingSegmentsMember cop:OtherInternationalSegmentMember 2019-12-31 0001163165 us-gaap:OperatingSegmentsMember cop:OtherInternationalSegmentMember 2018-12-18 0001163165 us-gaap:OperatingSegmentsMember cop:OtherInternationalSegmentMember 2017-12-31 0001163165 us-gaap:OperatingSegmentsMember us-gaap:ScenarioPlanMember srt:AsiaPacificMember cop:AustraliawestassetsMember 2019-10-01 2019-10-31 0001163165 us-gaap:OperatingSegmentsMember srt:AsiaPacificMember cop:AustraliawestassetsMember 2019-10-31 0001163165 us-gaap:OperatingSegmentsMember srt:AsiaPacificMember cop:AustraliawestassetsMember 2019-01-01 2019-12-31 0001163165 us-gaap:OperatingSegmentsMember us-gaap:ScenarioPlanMember cop:LowerFortyEightSegmentMember cop:NiobraraMember 2019-10-01 2019-12-31 0001163165 us-gaap:OperatingSegmentsMember cop:LowerFortyEightSegmentMember cop:NiobraraMember 2019-12-31 0001163165 us-gaap:OperatingSegmentsMember cop:LowerFortyEightSegmentMember cop:NiobraraMember 2017-01-01 2017-12-31 0001163165 us-gaap:OperatingSegmentsMember cop:LowerFortyEightSegmentMember cop:NiobraraMember 2018-01-01 2018-12-31 0001163165 us-gaap:OperatingSegmentsMember cop:LowerFortyEightSegmentMember cop:MagnoliafieldandplatformMember 2019-10-01 2019-12-31 0001163165 us-gaap:OperatingSegmentsMember cop:LowerFortyEightSegmentMember cop:MagnoliafieldandplatformMember 2019-12-31 0001163165 us-gaap:AssetRetirementObligationCostsMember us-gaap:OperatingSegmentsMember cop:LowerFortyEightSegmentMember cop:MagnoliafieldandplatformMember 2019-12-31 0001163165 us-gaap:OperatingSegmentsMember cop:LowerFortyEightSegmentMember cop:UndevelopedLeaseholdAssetsMember 2018-04-01 2018-06-30 0001163165 us-gaap:OperatingSegmentsMember cop:LowerFortyEightSegmentMember cop:BarnettMember 2018-10-01 2018-10-31 0001163165 us-gaap:AssetRetirementObligationCostsMember us-gaap:OperatingSegmentsMember cop:LowerFortyEightSegmentMember cop:BarnettMember 2018-10-31 0001163165 us-gaap:OperatingSegmentsMember cop:CertainunitedkingdomassetsmemberMember cop:EuropeMiddleEastAndNorthAfricaSegmentMember 2018-12-18 0001163165 cop:PSUCashSettledProgramMember 2017-01-01 2017-12-31 0001163165 us-gaap:OperatingSegmentsMember cop:EuropeMiddleEastAndNorthAfricaSegmentMember 2019-01-01 2019-12-31 0001163165 us-gaap:OperatingSegmentsMember cop:EuropeMiddleEastAndNorthAfricaSegmentMember 2018-01-01 2018-12-31 0001163165 us-gaap:OperatingSegmentsMember cop:EuropeMiddleEastAndNorthAfricaSegmentMember 2017-01-01 2017-12-31 0001163165 us-gaap:OperatingSegmentsMember cop:AsiaPacificAndMiddleEastMember 2019-01-01 2019-12-31 0001163165 us-gaap:OperatingSegmentsMember cop:AsiaPacificAndMiddleEastMember 2018-01-01 2018-12-31 0001163165 us-gaap:OperatingSegmentsMember cop:AsiaPacificAndMiddleEastMember 2017-01-01 2017-12-31 0001163165 us-gaap:OperatingSegmentsMember cop:OtherInternationalSegmentMember 2019-01-01 2019-12-31 0001163165 us-gaap:OperatingSegmentsMember cop:OtherInternationalSegmentMember 2018-01-01 2018-12-31 0001163165 us-gaap:OperatingSegmentsMember cop:OtherInternationalSegmentMember 2017-01-01 2017-12-31 0001163165 us-gaap:IntersegmentEliminationMember cop:CanadaSegmentMember 2019-01-01 2019-12-31 0001163165 us-gaap:IntersegmentEliminationMember cop:CanadaSegmentMember 2018-01-01 2018-12-31 0001163165 us-gaap:IntersegmentEliminationMember cop:CanadaSegmentMember 2017-01-01 2017-12-31 0001163165 us-gaap:OperatingSegmentsMember cop:AlaskaSegmentMember 2019-01-01 2019-12-31 0001163165 us-gaap:OperatingSegmentsMember cop:AlaskaSegmentMember 2018-01-01 2018-12-31 0001163165 us-gaap:OperatingSegmentsMember cop:AlaskaSegmentMember 2017-01-01 2017-12-31 0001163165 us-gaap:OperatingSegmentsMember cop:CanadaSegmentMember 2019-01-01 2019-12-31 0001163165 us-gaap:OperatingSegmentsMember cop:CanadaSegmentMember 2018-01-01 2018-12-31 0001163165 us-gaap:OperatingSegmentsMember cop:CanadaSegmentMember 2017-01-01 2017-12-31 0001163165 us-gaap:OperatingSegmentsMember srt:AsiaPacificMember 2019-01-01 2019-12-31 0001163165 us-gaap:OperatingSegmentsMember srt:AsiaPacificMember 2018-01-01 2018-12-31 0001163165 us-gaap:OperatingSegmentsMember srt:AsiaPacificMember 2017-01-01 2017-12-31 0001163165 country:EC cop:CleanupRemediationActivitiesMember cop:PenrencoEcuadorLimitedMember 2019-09-01 2019-09-30 0001163165 cop:UKSubsidiariesMember 2019-01-01 2019-12-31 0001163165 cop:CanadaSegmentMember 2019-01-01 2019-12-31 0001163165 cop:CanadaSegmentMember 2018-01-01 2018-12-31 0001163165 cop:CanadaSegmentMember 2017-01-01 2017-12-31 0001163165 us-gaap:OperatingSegmentsMember srt:AsiaPacificMember cop:AthenaFieldMember 2019-12-31 0001163165 us-gaap:AssetRetirementObligationCostsMember us-gaap:OperatingSegmentsMember srt:AsiaPacificMember cop:AustraliawestassetsMember 2019-10-31 0001163165 us-gaap:OperatingSegmentsMember srt:AsiaPacificMember cop:AustraliawestassetsMember 2019-12-31 0001163165 us-gaap:OperatingSegmentsMember srt:AsiaPacificMember cop:AustraliawestassetsMember 2017-01-01 2017-12-31 0001163165 us-gaap:OperatingSegmentsMember cop:LowerFortyEightSegmentMember cop:NiobraraMember 2019-10-01 2019-12-31 0001163165 us-gaap:OperatingSegmentsMember cop:LowerFortyEightSegmentMember cop:NiobraraMember 2019-01-01 2019-12-31 0001163165 us-gaap:OperatingSegmentsMember srt:AsiaPacificMember cop:GreatersunrisefieldsMember 2019-06-30 0001163165 us-gaap:OperatingSegmentsMember us-gaap:ScenarioPlanMember cop:LowerFortyEightSegmentMember cop:OtherPropertiesMember 2020-01-01 2020-01-31 0001163165 us-gaap:OperatingSegmentsMember cop:LowerFortyEightSegmentMember cop:UndevelopedLeaseholdAssetsMember 2018-10-01 2018-12-31 0001163165 us-gaap:OperatingSegmentsMember cop:LowerFortyEightSegmentMember cop:UndevelopedLeaseholdAssetsMember 2018-07-01 2018-09-30 0001163165 us-gaap:OperatingSegmentsMember cop:LowerFortyEightSegmentMember cop:BarnettMember 2018-12-31 0001163165 us-gaap:OperatingSegmentsMember cop:LowerFortyEightSegmentMember cop:BarnettMember 2018-10-31 0001163165 us-gaap:OperatingSegmentsMember cop:LowerFortyEightSegmentMember cop:BarnettMember 2018-01-01 2018-12-31 0001163165 us-gaap:OperatingSegmentsMember cop:LowerFortyEightSegmentMember cop:BarnettMember 2017-01-01 2017-12-31 0001163165 us-gaap:OperatingSegmentsMember cop:CertainunitedkingdomassetsmemberMember cop:EuropeMiddleEastAndNorthAfricaSegmentMember 2018-10-01 2018-12-31 0001163165 us-gaap:OperatingSegmentsMember srt:AsiaPacificMember cop:BarossaProjectMember 2019-12-31 0001163165 us-gaap:OperatingSegmentsMember srt:AsiaPacificMember cop:DarwinLNGFacilityMember 2019-12-31 0001163165 us-gaap:OperatingSegmentsMember srt:AsiaPacificMember cop:PoseidonFieldMember 2019-12-31 0001163165 us-gaap:AssetRetirementObligationCostsMember us-gaap:OperatingSegmentsMember srt:AsiaPacificMember cop:AustraliawestassetsMember 2019-12-31 0001163165 us-gaap:OperatingSegmentsMember srt:AsiaPacificMember cop:AustraliawestassetsMember 2018-01-01 2018-12-31 0001163165 us-gaap:AssetRetirementObligationCostsMember us-gaap:OperatingSegmentsMember cop:LowerFortyEightSegmentMember cop:NiobraraMember 2019-12-31 0001163165 us-gaap:OperatingSegmentsMember srt:AsiaPacificMember cop:GreatersunrisefieldsMember 2019-04-01 2019-06-30 0001163165 us-gaap:OperatingSegmentsMember cop:LowerFortyEightSegmentMember cop:OtherPropertiesMember 2018-01-01 2018-03-31 0001163165 us-gaap:OperatingSegmentsMember cop:LowerFortyEightSegmentMember cop:BarnettMember 2017-12-31 0001163165 us-gaap:OperatingSegmentsMember cop:CertainunitedkingdomassetsmemberMember cop:EuropeMiddleEastAndNorthAfricaSegmentMember 2017-01-01 2017-12-31 0001163165 us-gaap:OperatingSegmentsMember cop:LowerFortyEightSegmentMember cop:SanjuanbasinmemberMember 2017-01-01 2017-07-31 0001163165 us-gaap:OperatingSegmentsMember cop:LowerFortyEightSegmentMember cop:SanjuanbasinmemberMember 2017-07-31 0001163165 us-gaap:OperatingSegmentsMember cop:LowerFortyEightSegmentMember cop:PanhandlememberMember 2017-09-30 0001163165 us-gaap:OperatingSegmentsMember cop:LowerFortyEightSegmentMember cop:PanhandlememberMember 2017-01-01 2017-12-31 0001163165 cop:ClairFieldMember 2019-01-01 2019-12-31 0001163165 cop:ClairFieldMember 2019-07-01 2019-09-30 0001163165 us-gaap:ForeignPlanMember us-gaap:PensionPlansDefinedBenefitMember us-gaap:QualifiedPlanMember cop:CertainunitedkingdomassetsmemberMember 2018-12-31 0001163165 us-gaap:OperatingSegmentsMember cop:LowerFortyEightSegmentMember cop:CentralLouisianaAustinChalkMember 2019-01-01 2019-12-31 0001163165 us-gaap:OperatingSegmentsMember cop:LowerFortyEightSegmentMember cop:CertainDevelopedPropertiesMember 2017-01-01 2017-12-31 0001163165 us-gaap:OperatingSegmentsMember srt:AsiaPacificMember cop:AustraliaPacificLNGMember 2017-01-01 2017-12-31 0001163165 us-gaap:OperatingSegmentsMember cop:LowerFortyEightSegmentMember cop:MineralAssetsMember 2017-01-01 2017-12-31 0001163165 2019-12-02 0001163165 2019-10-01 2019-12-31 0001163165 us-gaap:OperatingSegmentsMember cop:AlaskaSegmentMember cop:KuparukAssetsMember 2018-05-01 2018-05-31 0001163165 us-gaap:OperatingSegmentsMember cop:AlaskaSegmentMember cop:KuparukAssetsMember 2018-05-31 0001163165 us-gaap:OperatingSegmentsMember cop:AlaskaSegmentMember cop:KuparukAssetsMember 2018-10-01 2018-12-31 0001163165 us-gaap:OperatingSegmentsMember cop:AlaskaSegmentMember cop:KuparukAssetsMember 2018-12-18 0001163165 srt:ParentCompanyMember 2016-12-31 0001163165 us-gaap:OperatingSegmentsMember cop:CertainunitedkingdomassetsmemberMember cop:EuropeMiddleEastAndNorthAfricaSegmentMember 2018-01-01 2018-12-31 0001163165 us-gaap:OperatingSegmentsMember cop:LowerFortyEightSegmentMember cop:SanjuanbasinmemberMember 2019-01-01 2019-12-31 0001163165 us-gaap:OperatingSegmentsMember cop:LowerFortyEightSegmentMember cop:SanjuanbasinmemberMember 2018-01-01 2018-12-31 0001163165 us-gaap:OperatingSegmentsMember cop:LowerFortyEightSegmentMember cop:SanjuanbasinmemberMember 2018-04-01 2018-06-30 0001163165 us-gaap:OperatingSegmentsMember cop:LowerFortyEightSegmentMember cop:SanjuanbasinmemberMember 2017-01-01 2017-12-31 0001163165 us-gaap:AssetRetirementObligationCostsMember us-gaap:OperatingSegmentsMember cop:LowerFortyEightSegmentMember cop:PanhandlememberMember 2019-09-30 0001163165 cop:ClairFieldMember 2019-12-31 0001163165 us-gaap:ForeignPlanMember us-gaap:PensionPlansDefinedBenefitMember us-gaap:QualifiedPlanMember cop:CertainunitedkingdomassetsmemberMember 2019-07-01 2019-09-30 0001163165 us-gaap:OperatingSegmentsMember cop:AlaskaSegmentMember cop:CancelledprojectMember 2018-01-01 2018-12-31 0001163165 us-gaap:OperatingSegmentsMember cop:CertainProjectsInEuropeAndNorthAfricaMember cop:EuropeMiddleEastAndNorthAfricaSegmentMember 2018-01-01 2018-12-31 0001163165 us-gaap:OperatingSegmentsMember cop:AlaskaSegmentMember cop:NonOperatedProducingPropertyMember 2017-01-01 2017-12-31 0001163165 us-gaap:OperatingSegmentsMember cop:CertainProjectsInEuropeAndNorthAfricaMember cop:EuropeMiddleEastAndNorthAfricaSegmentMember 2017-01-01 2017-12-31 0001163165 us-gaap:OperatingSegmentsMember cop:LowerFortyEightSegmentMember cop:ShenandoahLeaseholdMember 2017-01-01 2017-12-31 0001163165 us-gaap:CorporateDebtSecuritiesMember cop:RemainingMaturitiesWithinOneYearMember 2019-12-31 0001163165 us-gaap:CorporateDebtSecuritiesMember cop:RemainingMaturitiesGreaterThanOneYearMember 2019-12-31 0001163165 us-gaap:USGovernmentDebtSecuritiesMember cop:RemainingMaturitiesWithinOneYearMember 2019-12-31 0001163165 us-gaap:USGovernmentDebtSecuritiesMember cop:RemainingMaturitiesGreaterThanOneYearMember 2019-12-31 0001163165 us-gaap:AssetRetirementObligationCostsMember us-gaap:OperatingSegmentsMember cop:AlaskaSegmentMember cop:KuparukAssetsMember 2018-12-18 0001163165 cop:ConocoPhillipsCompanyMember 2019-01-01 2019-12-31 0001163165 us-gaap:OperatingSegmentsMember cop:UKSubsidiariesMember cop:EuropeMiddleEastAndNorthAfricaSegmentMember 2019-09-01 2019-09-30 0001163165 us-gaap:OperatingSegmentsMember cop:UKSubsidiariesMember cop:EuropeMiddleEastAndNorthAfricaSegmentMember 2019-09-30 0001163165 us-gaap:OperatingSegmentsMember cop:UKSubsidiariesMember cop:EuropeMiddleEastAndNorthAfricaSegmentMember 2018-01-01 2018-12-31 0001163165 us-gaap:OperatingSegmentsMember cop:UKSubsidiariesMember cop:EuropeMiddleEastAndNorthAfricaSegmentMember 2017-01-01 2017-12-31 0001163165 us-gaap:OperatingSegmentsMember cop:CanadaSegmentMember cop:FosterCreekChristinaLakeAndWesternCanadaGasPropertiesMember 2017-05-17 0001163165 us-gaap:OperatingSegmentsMember cop:CanadaSegmentMember cop:FosterCreekChristinaLakeFcclMember 2017-01-01 2017-12-31 0001163165 us-gaap:OperatingSegmentsMember cop:CanadaSegmentMember cop:WesternCanadaGasPropertiesMember 2017-01-01 2017-12-31 0001163165 us-gaap:OperatingSegmentsMember cop:CanadaSegmentMember cop:FosterCreekChristinaLakeAndWesternCanadaGasPropertiesMember 2018-01-01 2018-12-31 0001163165 us-gaap:AssetRetirementObligationCostsMember us-gaap:OperatingSegmentsMember cop:CanadaSegmentMember cop:WesternCanadaGasPropertiesMember 2017-05-17 0001163165 country:AO cop:OtherInternationalSegmentMember cop:AthenaDrillingRigMember 2017-02-01 2017-02-28 0001163165 us-gaap:AssetRetirementObligationCostsMember us-gaap:OperatingSegmentsMember cop:CertainunitedkingdomassetsmemberMember cop:EuropeMiddleEastAndNorthAfricaSegmentMember 2018-12-18 0001163165 us-gaap:OperatingSegmentsMember us-gaap:ScenarioPlanMember cop:LowerFortyEightSegmentMember cop:SanjuanbasinmemberMember 2017-07-31 0001163165 us-gaap:OperatingSegmentsMember cop:LowerFortyEightSegmentMember cop:PanhandlememberMember 2017-09-01 2017-09-30 0001163165 us-gaap:OtherCurrentLiabilitiesMember 2019-12-31 0001163165 us-gaap:EmployeeStockOptionMember cop:TwentyFourteenOmnibusStockAndPerformanceIncentivePlanOfConocoPhillipsMember 2019-12-31 0001163165 us-gaap:ForeignPlanMember us-gaap:PensionPlansDefinedBenefitMember us-gaap:QualifiedPlanMember cop:CertainunitedkingdomassetsmemberMember 2019-09-30 0001163165 us-gaap:OperatingSegmentsMember cop:LowerFortyEightSegmentMember cop:NiobraraMember 2019-01-01 2019-12-31 0001163165 us-gaap:OperatingSegmentsMember cop:LowerFortyEightSegmentMember cop:BarnettMember 2018-01-01 2018-12-31 0001163165 us-gaap:OperatingSegmentsMember cop:CanadaSegmentMember cop:CancelledprojectMember 2017-01-01 2017-12-31 0001163165 us-gaap:CommercialPaperMember cop:RemainingMaturitiesWithinOneYearMember 2019-12-31 0001163165 us-gaap:AssetBackedSecuritiesMember cop:RemainingMaturitiesGreaterThanOneYearMember 2019-12-31 0001163165 us-gaap:CashMember 2018-12-31 0001163165 us-gaap:AssetRetirementObligationCostsMember us-gaap:OperatingSegmentsMember cop:AlaskaSegmentMember cop:KuparukAssetsMember 2018-05-31 0001163165 srt:ReportableLegalEntitiesMember cop:ConocoPhillipsCompanyMember 2016-12-31 0001163165 cop:ConocoPhillipsCompanyMember 2017-01-01 2017-12-31 0001163165 srt:ParentCompanyMember 2017-01-01 2017-12-31 0001163165 cop:ConocoPhillipsCompanyMember 2018-01-01 2018-12-31 0001163165 srt:ParentCompanyMember cop:BurlingtonResourcesLLCMember 2019-01-01 2019-12-31 0001163165 us-gaap:OperatingSegmentsMember cop:LowerFortyEightSegmentMember cop:GoldenPassMember 2019-01-31 0001163165 us-gaap:OperatingSegmentsMember cop:LowerFortyEightSegmentMember cop:GoldenPassMember 2019-01-01 2019-03-31 0001163165 us-gaap:AssetRetirementObligationCostsMember us-gaap:OperatingSegmentsMember cop:UKSubsidiariesMember cop:EuropeMiddleEastAndNorthAfricaSegmentMember 2019-09-30 0001163165 us-gaap:OperatingSegmentsMember cop:UKSubsidiariesMember cop:EuropeMiddleEastAndNorthAfricaSegmentMember 2019-01-01 2019-12-31 0001163165 us-gaap:OperatingSegmentsMember cop:CanadaSegmentMember cop:FosterCreekChristinaLakeAndWesternCanadaGasPropertiesMember 2017-01-01 2017-05-17 0001163165 us-gaap:OperatingSegmentsMember cop:CanadaSegmentMember cop:FosterCreekChristinaLakeFcclMember 2017-01-01 2017-05-17 0001163165 us-gaap:OperatingSegmentsMember cop:CanadaSegmentMember cop:WesternCanadaGasPropertiesMember 2017-05-17 0001163165 us-gaap:OperatingSegmentsMember cop:CanadaSegmentMember cop:FosterCreekChristinaLakeAndWesternCanadaGasPropertiesMember 2017-01-01 2017-12-31 0001163165 srt:ParentCompanyMember 2018-01-01 2018-12-31 0001163165 srt:ParentCompanyMember 2019-01-01 2019-12-31 0001163165 us-gaap:OperatingSegmentsMember us-gaap:ScenarioPlanMember cop:UKSubsidiariesMember cop:EuropeMiddleEastAndNorthAfricaSegmentMember 2019-04-01 2019-04-30 0001163165 us-gaap:OperatingSegmentsMember cop:UKSubsidiariesMember cop:EuropeMiddleEastAndNorthAfricaSegmentMember 2019-12-31 0001163165 us-gaap:OperatingSegmentsMember cop:CanadaSegmentMember cop:FosterCreekChristinaLakeAndWesternCanadaGasPropertiesMember 2019-01-01 2019-12-31 0001163165 cop:LowerFortyEightSegmentMember cop:CentralLouisianaAustinChalkMember 2019-01-01 2019-12-31 0001163165 us-gaap:FairValueInputsLevel3Member us-gaap:InsuranceContractRightsAndObligationsFairValueOptionMember us-gaap:PensionPlansDefinedBenefitMember country:US 2019-12-31 0001163165 us-gaap:DefinedBenefitPlanDebtSecurityMember us-gaap:FairValueInputsLevel3Member us-gaap:InsuranceContractRightsAndObligationsFairValueOptionMember us-gaap:PensionPlansDefinedBenefitMember country:US 2019-12-31 0001163165 us-gaap:FairValueInputsLevel3Member us-gaap:InsuranceContractRightsAndObligationsFairValueOptionMember us-gaap:PensionPlansDefinedBenefitMember country:US 2018-12-31 0001163165 us-gaap:DefinedBenefitPlanDebtSecurityMember us-gaap:FairValueInputsLevel3Member us-gaap:InsuranceContractRightsAndObligationsFairValueOptionMember us-gaap:PensionPlansDefinedBenefitMember country:US 2018-12-31 0001163165 us-gaap:FairValueInputsLevel3Member us-gaap:InsuranceContractRightsAndObligationsFairValueOptionMember us-gaap:PensionPlansDefinedBenefitMember country:US 2019-01-01 2019-12-31 0001163165 country:US 2019-12-31 0001163165 country:US 2019-01-01 2019-12-31 0001163165 us-gaap:RetirementPlanTaxStatusDomain country:US 2019-12-31 0001163165 country:US 2017-01-01 2017-12-31 0001163165 country:US cop:DefinedContributionPlanCompanyRetirementContributionMember 2019-01-01 2019-12-31 0001163165 country:US 2018-01-01 2018-12-31 0001163165 us-gaap:CommonStockMember cop:CenovusEnergyMember 2017-05-17 0001163165 us-gaap:EquityFundsMember us-gaap:FairValueInputsLevel1Member country:US 2019-12-31 0001163165 us-gaap:EquityFundsMember us-gaap:FairValueInputsLevel2Member country:US 2019-12-31 0001163165 us-gaap:EquityFundsMember us-gaap:FairValueInputsLevel3Member country:US 2019-12-31 0001163165 us-gaap:DomesticCorporateDebtSecuritiesMember us-gaap:FairValueInputsLevel1Member country:US 2019-12-31 0001163165 us-gaap:DomesticCorporateDebtSecuritiesMember us-gaap:FairValueInputsLevel2Member country:US 2019-12-31 0001163165 us-gaap:DomesticCorporateDebtSecuritiesMember us-gaap:FairValueInputsLevel3Member country:US 2019-12-31 0001163165 us-gaap:FairValueInputsLevel1Member us-gaap:MutualFundMember country:US 2019-12-31 0001163165 us-gaap:FairValueInputsLevel2Member us-gaap:MutualFundMember country:US 2019-12-31 0001163165 us-gaap:FairValueInputsLevel3Member us-gaap:MutualFundMember country:US 2019-12-31 0001163165 us-gaap:DefinedBenefitPlanDerivativeMember country:US 2019-12-31 0001163165 us-gaap:DefinedBenefitPlanRealEstateMember country:US 2019-12-31 0001163165 us-gaap:DefinedBenefitPlanEquitySecuritiesUsMember us-gaap:FairValueInputsLevel1Member us-gaap:ForeignPlanMember 2019-12-31 0001163165 us-gaap:DefinedBenefitPlanEquitySecuritiesUsMember us-gaap:FairValueInputsLevel2Member us-gaap:ForeignPlanMember 2019-12-31 0001163165 us-gaap:DefinedBenefitPlanEquitySecuritiesUsMember us-gaap:FairValueInputsLevel3Member us-gaap:ForeignPlanMember 2019-12-31 0001163165 us-gaap:DefinedBenefitPlanEquitySecuritiesNonUsMember us-gaap:FairValueInputsLevel1Member us-gaap:ForeignPlanMember 2019-12-31 0001163165 us-gaap:DefinedBenefitPlanEquitySecuritiesNonUsMember us-gaap:FairValueInputsLevel2Member us-gaap:ForeignPlanMember 2019-12-31 0001163165 us-gaap:DefinedBenefitPlanEquitySecuritiesNonUsMember us-gaap:FairValueInputsLevel3Member us-gaap:ForeignPlanMember 2019-12-31 0001163165 us-gaap:EquityFundsMember us-gaap:FairValueInputsLevel1Member us-gaap:ForeignPlanMember 2019-12-31 0001163165 us-gaap:EquityFundsMember us-gaap:FairValueInputsLevel2Member us-gaap:ForeignPlanMember 2019-12-31 0001163165 us-gaap:EquityFundsMember us-gaap:FairValueInputsLevel3Member us-gaap:ForeignPlanMember 2019-12-31 0001163165 us-gaap:FairValueInputsLevel1Member us-gaap:ForeignPlanMember us-gaap:USGovernmentDebtSecuritiesMember 2019-12-31 0001163165 us-gaap:FairValueInputsLevel2Member us-gaap:ForeignPlanMember us-gaap:USGovernmentDebtSecuritiesMember 2019-12-31 0001163165 us-gaap:FairValueInputsLevel3Member us-gaap:ForeignPlanMember us-gaap:USGovernmentDebtSecuritiesMember 2019-12-31 0001163165 us-gaap:DomesticCorporateDebtSecuritiesMember us-gaap:FairValueInputsLevel1Member us-gaap:ForeignPlanMember 2019-12-31 0001163165 us-gaap:DomesticCorporateDebtSecuritiesMember us-gaap:FairValueInputsLevel2Member us-gaap:ForeignPlanMember 2019-12-31 0001163165 us-gaap:DomesticCorporateDebtSecuritiesMember us-gaap:FairValueInputsLevel3Member us-gaap:ForeignPlanMember 2019-12-31 0001163165 us-gaap:DefinedBenefitPlanEquitySecuritiesUsMember us-gaap:ForeignPlanMember 2019-12-31 0001163165 us-gaap:DefinedBenefitPlanEquitySecuritiesNonUsMember us-gaap:ForeignPlanMember 2019-12-31 0001163165 us-gaap:EquityFundsMember us-gaap:ForeignPlanMember 2019-12-31 0001163165 us-gaap:ForeignPlanMember us-gaap:USGovernmentDebtSecuritiesMember 2019-12-31 0001163165 us-gaap:FairValueInputsLevel1Member us-gaap:ForeignPlanMember 2019-12-31 0001163165 us-gaap:FairValueInputsLevel2Member us-gaap:ForeignPlanMember 2019-12-31 0001163165 us-gaap:FairValueInputsLevel3Member us-gaap:ForeignPlanMember 2019-12-31 0001163165 us-gaap:ForeignPlanMember 2019-12-31 0001163165 us-gaap:DefinedBenefitPlanEquitySecuritiesUsMember us-gaap:FairValueInputsLevel1Member country:US 2018-12-31 0001163165 us-gaap:DefinedBenefitPlanEquitySecuritiesUsMember us-gaap:FairValueInputsLevel2Member country:US 2018-12-31 0001163165 us-gaap:DefinedBenefitPlanEquitySecuritiesUsMember us-gaap:FairValueInputsLevel3Member country:US 2018-12-31 0001163165 us-gaap:DefinedBenefitPlanEquitySecuritiesNonUsMember us-gaap:FairValueInputsLevel1Member country:US 2018-12-31 0001163165 us-gaap:DefinedBenefitPlanEquitySecuritiesNonUsMember us-gaap:FairValueInputsLevel2Member country:US 2018-12-31 0001163165 us-gaap:DefinedBenefitPlanEquitySecuritiesNonUsMember us-gaap:FairValueInputsLevel3Member country:US 2018-12-31 0001163165 us-gaap:EquityFundsMember us-gaap:FairValueInputsLevel1Member country:US 2018-12-31 0001163165 us-gaap:EquityFundsMember us-gaap:FairValueInputsLevel2Member country:US 2018-12-31 0001163165 us-gaap:EquityFundsMember us-gaap:FairValueInputsLevel3Member country:US 2018-12-31 0001163165 us-gaap:FairValueInputsLevel1Member us-gaap:USGovernmentDebtSecuritiesMember country:US 2018-12-31 0001163165 us-gaap:FairValueInputsLevel2Member us-gaap:USGovernmentDebtSecuritiesMember country:US 2018-12-31 0001163165 us-gaap:FairValueInputsLevel3Member us-gaap:USGovernmentDebtSecuritiesMember country:US 2018-12-31 0001163165 us-gaap:DomesticCorporateDebtSecuritiesMember us-gaap:FairValueInputsLevel1Member country:US 2018-12-31 0001163165 us-gaap:DomesticCorporateDebtSecuritiesMember us-gaap:FairValueInputsLevel2Member country:US 2018-12-31 0001163165 us-gaap:DomesticCorporateDebtSecuritiesMember us-gaap:FairValueInputsLevel3Member country:US 2018-12-31 0001163165 us-gaap:FairValueInputsLevel1Member us-gaap:MutualFundMember country:US 2018-12-31 0001163165 us-gaap:FairValueInputsLevel2Member us-gaap:MutualFundMember country:US 2018-12-31 0001163165 us-gaap:FairValueInputsLevel3Member us-gaap:MutualFundMember country:US 2018-12-31 0001163165 us-gaap:DefinedBenefitPlanCashAndCashEquivalentsMember us-gaap:FairValueInputsLevel1Member country:US 2018-12-31 0001163165 us-gaap:DefinedBenefitPlanCashAndCashEquivalentsMember us-gaap:FairValueInputsLevel2Member country:US 2018-12-31 0001163165 us-gaap:DefinedBenefitPlanCashAndCashEquivalentsMember us-gaap:FairValueInputsLevel3Member country:US 2018-12-31 0001163165 us-gaap:DefinedBenefitPlanDerivativeMember us-gaap:FairValueInputsLevel3Member country:US 2018-12-31 0001163165 us-gaap:DefinedBenefitPlanRealEstateMember us-gaap:FairValueInputsLevel3Member country:US 2018-12-31 0001163165 country:US 2018-12-31 0001163165 us-gaap:FairValueInputsLevel1Member us-gaap:ForeignPlanMember us-gaap:USGovernmentDebtSecuritiesMember 2018-12-31 0001163165 us-gaap:FairValueInputsLevel2Member us-gaap:ForeignPlanMember us-gaap:USGovernmentDebtSecuritiesMember 2018-12-31 0001163165 us-gaap:FairValueInputsLevel3Member us-gaap:ForeignPlanMember us-gaap:USGovernmentDebtSecuritiesMember 2018-12-31 0001163165 us-gaap:DomesticCorporateDebtSecuritiesMember us-gaap:FairValueInputsLevel1Member us-gaap:ForeignPlanMember 2018-12-31 0001163165 us-gaap:DomesticCorporateDebtSecuritiesMember us-gaap:FairValueInputsLevel2Member us-gaap:ForeignPlanMember 2018-12-31 0001163165 us-gaap:DomesticCorporateDebtSecuritiesMember us-gaap:FairValueInputsLevel3Member us-gaap:ForeignPlanMember 2018-12-31 0001163165 us-gaap:FairValueInputsLevel1Member us-gaap:ForeignPlanMember us-gaap:MutualFundMember 2018-12-31 0001163165 us-gaap:FairValueInputsLevel2Member us-gaap:ForeignPlanMember us-gaap:MutualFundMember 2018-12-31 0001163165 us-gaap:FairValueInputsLevel3Member us-gaap:ForeignPlanMember us-gaap:MutualFundMember 2018-12-31 0001163165 us-gaap:DefinedBenefitPlanCashAndCashEquivalentsMember us-gaap:FairValueInputsLevel1Member us-gaap:ForeignPlanMember 2018-12-31 0001163165 us-gaap:DefinedBenefitPlanCashAndCashEquivalentsMember us-gaap:FairValueInputsLevel2Member us-gaap:ForeignPlanMember 2018-12-31 0001163165 us-gaap:DefinedBenefitPlanCashAndCashEquivalentsMember us-gaap:FairValueInputsLevel3Member us-gaap:ForeignPlanMember 2018-12-31 0001163165 us-gaap:DefinedBenefitPlanDerivativeMember us-gaap:ForeignPlanMember 2018-12-31 0001163165 us-gaap:DefinedBenefitPlanRealEstateMember us-gaap:ForeignPlanMember 2018-12-31 0001163165 us-gaap:FairValueDisclosureItemAmountsDomain us-gaap:FairValueInputsLevel1Member us-gaap:ForeignPlanMember 2018-12-31 0001163165 us-gaap:FairValueDisclosureItemAmountsDomain us-gaap:FairValueInputsLevel2Member us-gaap:ForeignPlanMember 2018-12-31 0001163165 us-gaap:FairValueDisclosureItemAmountsDomain us-gaap:FairValueInputsLevel3Member us-gaap:ForeignPlanMember 2018-12-31 0001163165 us-gaap:FairValueDisclosureItemAmountsDomain us-gaap:FairValueInputsLevel1Member us-gaap:ForeignPlanMember 2019-12-31 0001163165 us-gaap:FairValueDisclosureItemAmountsDomain us-gaap:FairValueInputsLevel2Member us-gaap:ForeignPlanMember 2019-12-31 0001163165 us-gaap:FairValueDisclosureItemAmountsDomain us-gaap:FairValueInputsLevel3Member us-gaap:ForeignPlanMember 2019-12-31 0001163165 us-gaap:BankTimeDepositsMember country:US 2018-12-31 0001163165 us-gaap:BankTimeDepositsMember us-gaap:FairValueInputsLevel1Member us-gaap:ForeignPlanMember 2018-12-31 0001163165 us-gaap:BankTimeDepositsMember us-gaap:FairValueInputsLevel2Member us-gaap:ForeignPlanMember 2018-12-31 0001163165 us-gaap:BankTimeDepositsMember us-gaap:FairValueInputsLevel3Member us-gaap:ForeignPlanMember 2018-12-31 0001163165 us-gaap:RevolvingCreditFacilityMember 2018-12-31 0001163165 cop:LowerFortyEightSegmentMember cop:PhysicalGasContractsMember 2018-01-01 2018-12-31 0001163165 cop:CanadaSegmentMember cop:PhysicalGasContractsMember 2018-01-01 2018-12-31 0001163165 cop:PhysicalGasContractsMember cop:EuropeMiddleEastAndNorthAfricaSegmentMember 2018-01-01 2018-12-31 0001163165 srt:MinimumMember cop:FloatingRateOnePointEightOnePercentToTwoPointThreeTwoPercentMember cop:FloatingRateNotesMember 2019-12-31 0001163165 srt:MaximumMember cop:FloatingRateOnePointEightOnePercentToTwoPointThreeTwoPercentMember cop:FloatingRateNotesMember 2019-12-31 0001163165 srt:MinimumMember cop:FloatingRateOnePointEightOnePercentToTwoPointThreeTwoPercentMember cop:FloatingRateNotesMember 2018-12-31 0001163165 srt:MaximumMember cop:FloatingRateOnePointEightOnePercentToTwoPointThreeTwoPercentMember cop:FloatingRateNotesMember 2018-12-31 0001163165 us-gaap:CommonStockMember cop:CenovusEnergyMember 2017-01-01 2017-05-17 0001163165 us-gaap:CommonStockMember cop:CenovusEnergyMember 2019-01-01 2019-12-31 0001163165 us-gaap:DefinedBenefitPlanEquitySecuritiesUsMember us-gaap:FairValueInputsLevel1Member country:US 2019-12-31 0001163165 us-gaap:DefinedBenefitPlanEquitySecuritiesUsMember us-gaap:FairValueInputsLevel2Member country:US 2019-12-31 0001163165 us-gaap:DefinedBenefitPlanEquitySecuritiesUsMember us-gaap:FairValueInputsLevel3Member country:US 2019-12-31 0001163165 us-gaap:FairValueInputsLevel1Member us-gaap:USGovernmentDebtSecuritiesMember country:US 2019-12-31 0001163165 us-gaap:FairValueInputsLevel2Member us-gaap:USGovernmentDebtSecuritiesMember country:US 2019-12-31 0001163165 us-gaap:FairValueInputsLevel3Member us-gaap:USGovernmentDebtSecuritiesMember country:US 2019-12-31 0001163165 us-gaap:USGovernmentDebtSecuritiesMember country:US 2019-12-31 0001163165 us-gaap:DomesticCorporateDebtSecuritiesMember country:US 2019-12-31 0001163165 us-gaap:MutualFundMember country:US 2019-12-31 0001163165 us-gaap:DefinedBenefitPlanCashAndCashEquivalentsMember country:US 2019-12-31 0001163165 us-gaap:DefinedBenefitPlanDerivativeMember us-gaap:FairValueInputsLevel1Member country:US 2019-12-31 0001163165 us-gaap:DefinedBenefitPlanDerivativeMember us-gaap:FairValueInputsLevel2Member country:US 2019-12-31 0001163165 us-gaap:DefinedBenefitPlanDerivativeMember us-gaap:FairValueInputsLevel3Member country:US 2019-12-31 0001163165 us-gaap:DefinedBenefitPlanRealEstateMember us-gaap:FairValueInputsLevel1Member country:US 2019-12-31 0001163165 us-gaap:DefinedBenefitPlanRealEstateMember us-gaap:FairValueInputsLevel2Member country:US 2019-12-31 0001163165 us-gaap:DefinedBenefitPlanRealEstateMember us-gaap:FairValueInputsLevel3Member country:US 2019-12-31 0001163165 us-gaap:FairValueInputsLevel1Member country:US 2019-12-31 0001163165 us-gaap:FairValueInputsLevel2Member country:US 2019-12-31 0001163165 us-gaap:FairValueInputsLevel3Member country:US 2019-12-31 0001163165 us-gaap:DefinedBenefitPlanDerivativeMember us-gaap:FairValueInputsLevel1Member us-gaap:ForeignPlanMember 2019-12-31 0001163165 us-gaap:DefinedBenefitPlanDerivativeMember us-gaap:FairValueInputsLevel2Member us-gaap:ForeignPlanMember 2019-12-31 0001163165 us-gaap:DefinedBenefitPlanDerivativeMember us-gaap:FairValueInputsLevel3Member us-gaap:ForeignPlanMember 2019-12-31 0001163165 us-gaap:DefinedBenefitPlanRealEstateMember us-gaap:FairValueInputsLevel1Member us-gaap:ForeignPlanMember 2019-12-31 0001163165 us-gaap:DefinedBenefitPlanRealEstateMember us-gaap:FairValueInputsLevel2Member us-gaap:ForeignPlanMember 2019-12-31 0001163165 us-gaap:DefinedBenefitPlanRealEstateMember us-gaap:FairValueInputsLevel3Member us-gaap:ForeignPlanMember 2019-12-31 0001163165 us-gaap:DefinedBenefitPlanDerivativeMember us-gaap:ForeignPlanMember 2019-12-31 0001163165 us-gaap:DefinedBenefitPlanRealEstateMember us-gaap:ForeignPlanMember 2019-12-31 0001163165 us-gaap:DefinedBenefitPlanEquitySecuritiesUsMember country:US 2018-12-31 0001163165 us-gaap:DefinedBenefitPlanEquitySecuritiesNonUsMember country:US 2018-12-31 0001163165 us-gaap:EquityFundsMember country:US 2018-12-31 0001163165 us-gaap:DefinedBenefitPlanEquitySecuritiesUsMember us-gaap:ForeignPlanMember 2018-12-31 0001163165 us-gaap:DefinedBenefitPlanEquitySecuritiesNonUsMember us-gaap:ForeignPlanMember 2018-12-31 0001163165 us-gaap:EquityFundsMember us-gaap:ForeignPlanMember 2018-12-31 0001163165 us-gaap:DefinedBenefitPlanDerivativeMember us-gaap:FairValueInputsLevel1Member us-gaap:ForeignPlanMember 2018-12-31 0001163165 us-gaap:DefinedBenefitPlanDerivativeMember us-gaap:FairValueInputsLevel2Member us-gaap:ForeignPlanMember 2018-12-31 0001163165 us-gaap:DefinedBenefitPlanDerivativeMember us-gaap:FairValueInputsLevel3Member us-gaap:ForeignPlanMember 2018-12-31 0001163165 us-gaap:DefinedBenefitPlanRealEstateMember us-gaap:FairValueInputsLevel1Member us-gaap:ForeignPlanMember 2018-12-31 0001163165 us-gaap:DefinedBenefitPlanRealEstateMember us-gaap:FairValueInputsLevel2Member us-gaap:ForeignPlanMember 2018-12-31 0001163165 us-gaap:DefinedBenefitPlanRealEstateMember us-gaap:FairValueInputsLevel3Member us-gaap:ForeignPlanMember 2018-12-31 0001163165 us-gaap:FairValueInputsLevel1Member us-gaap:ForeignPlanMember 2018-12-31 0001163165 us-gaap:FairValueInputsLevel2Member us-gaap:ForeignPlanMember 2018-12-31 0001163165 us-gaap:FairValueInputsLevel3Member us-gaap:ForeignPlanMember 2018-12-31 0001163165 us-gaap:ForeignPlanMember us-gaap:PortionAtOtherThanFairValueFairValueDisclosureMember cop:DefinedBenefitPlanCommonCollectiveTrustEquitySecuritiesMember 2018-12-31 0001163165 us-gaap:DefinedBenefitPlanCommonCollectiveTrustMember us-gaap:ForeignPlanMember us-gaap:PortionAtOtherThanFairValueFairValueDisclosureMember 2018-12-31 0001163165 us-gaap:DefinedBenefitPlanCashAndCashEquivalentsMember us-gaap:ForeignPlanMember us-gaap:PortionAtOtherThanFairValueFairValueDisclosureMember 2018-12-31 0001163165 us-gaap:DefinedBenefitPlanRealEstateMember us-gaap:ForeignPlanMember us-gaap:PortionAtOtherThanFairValueFairValueDisclosureMember 2018-12-31 0001163165 us-gaap:FairValueDisclosureItemAmountsDomain us-gaap:FairValueInputsLevel1Member country:US 2018-12-31 0001163165 us-gaap:FairValueDisclosureItemAmountsDomain us-gaap:FairValueInputsLevel2Member country:US 2018-12-31 0001163165 us-gaap:FairValueDisclosureItemAmountsDomain us-gaap:FairValueInputsLevel3Member country:US 2018-12-31 0001163165 us-gaap:FairValueDisclosureItemAmountsDomain country:US 2018-12-31 0001163165 us-gaap:FairValueDisclosureItemAmountsDomain us-gaap:ForeignPlanMember 2018-12-31 0001163165 us-gaap:PortionAtOtherThanFairValueFairValueDisclosureMember country:US cop:DefinedBenefitPlanCommonCollectiveTrustEquitySecuritiesMember 2019-12-31 0001163165 us-gaap:DefinedBenefitPlanCommonCollectiveTrustMember us-gaap:PortionAtOtherThanFairValueFairValueDisclosureMember country:US 2019-12-31 0001163165 us-gaap:DefinedBenefitPlanCashAndCashEquivalentsMember us-gaap:PortionAtOtherThanFairValueFairValueDisclosureMember country:US 2019-12-31 0001163165 us-gaap:DefinedBenefitPlanRealEstateMember us-gaap:PortionAtOtherThanFairValueFairValueDisclosureMember country:US 2019-12-31 0001163165 us-gaap:ForeignPlanMember us-gaap:PortionAtOtherThanFairValueFairValueDisclosureMember cop:DefinedBenefitPlanCommonCollectiveTrustEquitySecuritiesMember 2019-12-31 0001163165 us-gaap:DefinedBenefitPlanCommonCollectiveTrustMember us-gaap:ForeignPlanMember us-gaap:PortionAtOtherThanFairValueFairValueDisclosureMember 2019-12-31 0001163165 us-gaap:DefinedBenefitPlanCashAndCashEquivalentsMember us-gaap:ForeignPlanMember us-gaap:PortionAtOtherThanFairValueFairValueDisclosureMember 2019-12-31 0001163165 us-gaap:DefinedBenefitPlanRealEstateMember us-gaap:ForeignPlanMember us-gaap:PortionAtOtherThanFairValueFairValueDisclosureMember 2019-12-31 0001163165 us-gaap:FairValueDisclosureItemAmountsDomain us-gaap:FairValueInputsLevel1Member country:US 2019-12-31 0001163165 us-gaap:FairValueDisclosureItemAmountsDomain us-gaap:FairValueInputsLevel2Member country:US 2019-12-31 0001163165 us-gaap:FairValueDisclosureItemAmountsDomain us-gaap:FairValueInputsLevel3Member country:US 2019-12-31 0001163165 us-gaap:FairValueDisclosureItemAmountsDomain country:US 2019-12-31 0001163165 cop:LowerFortyEightSegmentMember cop:PhysicalGasContractsMember 2019-01-01 2019-12-31 0001163165 cop:CanadaSegmentMember cop:PhysicalGasContractsMember 2019-01-01 2019-12-31 0001163165 cop:PhysicalGasContractsMember cop:EuropeMiddleEastAndNorthAfricaSegmentMember 2019-01-01 2019-12-31 0001163165 us-gaap:OtherNoncurrentAssetsMember country:AU 2019-12-31 0001163165 srt:MinimumMember cop:ZeroPointSixFourToOnePointSevenFourPercentIndustrialDevelopmentBondsMember cop:VariableRateDebtBondsMember 2019-12-31 0001163165 srt:MaximumMember cop:ZeroPointSixFourToOnePointSevenFourPercentIndustrialDevelopmentBondsMember cop:VariableRateDebtBondsMember 2019-12-31 0001163165 srt:MinimumMember cop:ZeroPointSixFourToOnePointSevenFourPercentIndustrialDevelopmentBondsMember cop:VariableRateDebtBondsMember 2018-12-31 0001163165 srt:MaximumMember cop:ZeroPointSixFourToOnePointSevenFourPercentIndustrialDevelopmentBondsMember cop:VariableRateDebtBondsMember 2018-12-31 0001163165 us-gaap:CommonStockMember cop:CenovusEnergyMember 2018-12-31 0001163165 us-gaap:DefinedBenefitPlanEquitySecuritiesNonUsMember us-gaap:FairValueInputsLevel1Member country:US 2019-12-31 0001163165 us-gaap:DefinedBenefitPlanEquitySecuritiesNonUsMember us-gaap:FairValueInputsLevel2Member country:US 2019-12-31 0001163165 us-gaap:DefinedBenefitPlanEquitySecuritiesNonUsMember us-gaap:FairValueInputsLevel3Member country:US 2019-12-31 0001163165 us-gaap:DefinedBenefitPlanEquitySecuritiesUsMember country:US 2019-12-31 0001163165 us-gaap:DefinedBenefitPlanEquitySecuritiesNonUsMember country:US 2019-12-31 0001163165 us-gaap:EquityFundsMember country:US 2019-12-31 0001163165 us-gaap:DefinedBenefitPlanCashAndCashEquivalentsMember us-gaap:FairValueInputsLevel1Member country:US 2019-12-31 0001163165 us-gaap:DefinedBenefitPlanCashAndCashEquivalentsMember us-gaap:FairValueInputsLevel2Member country:US 2019-12-31 0001163165 us-gaap:DefinedBenefitPlanCashAndCashEquivalentsMember us-gaap:FairValueInputsLevel3Member country:US 2019-12-31 0001163165 us-gaap:FairValueInputsLevel1Member us-gaap:ForeignPlanMember us-gaap:MutualFundMember 2019-12-31 0001163165 us-gaap:FairValueInputsLevel2Member us-gaap:ForeignPlanMember us-gaap:MutualFundMember 2019-12-31 0001163165 us-gaap:FairValueInputsLevel3Member us-gaap:ForeignPlanMember us-gaap:MutualFundMember 2019-12-31 0001163165 us-gaap:DefinedBenefitPlanCashAndCashEquivalentsMember us-gaap:FairValueInputsLevel1Member us-gaap:ForeignPlanMember 2019-12-31 0001163165 us-gaap:DefinedBenefitPlanCashAndCashEquivalentsMember us-gaap:FairValueInputsLevel2Member us-gaap:ForeignPlanMember 2019-12-31 0001163165 us-gaap:DefinedBenefitPlanCashAndCashEquivalentsMember us-gaap:FairValueInputsLevel3Member us-gaap:ForeignPlanMember 2019-12-31 0001163165 us-gaap:DomesticCorporateDebtSecuritiesMember us-gaap:ForeignPlanMember 2019-12-31 0001163165 us-gaap:ForeignPlanMember us-gaap:MutualFundMember 2019-12-31 0001163165 us-gaap:DefinedBenefitPlanCashAndCashEquivalentsMember us-gaap:ForeignPlanMember 2019-12-31 0001163165 us-gaap:USGovernmentDebtSecuritiesMember country:US 2018-12-31 0001163165 us-gaap:DomesticCorporateDebtSecuritiesMember country:US 2018-12-31 0001163165 us-gaap:MutualFundMember country:US 2018-12-31 0001163165 us-gaap:DefinedBenefitPlanCashAndCashEquivalentsMember country:US 2018-12-31 0001163165 us-gaap:DefinedBenefitPlanDerivativeMember country:US 2018-12-31 0001163165 us-gaap:DefinedBenefitPlanDerivativeMember us-gaap:FairValueInputsLevel1Member country:US 2018-12-31 0001163165 us-gaap:DefinedBenefitPlanDerivativeMember us-gaap:FairValueInputsLevel2Member country:US 2018-12-31 0001163165 us-gaap:DefinedBenefitPlanRealEstateMember country:US 2018-12-31 0001163165 us-gaap:DefinedBenefitPlanRealEstateMember us-gaap:FairValueInputsLevel1Member country:US 2018-12-31 0001163165 us-gaap:DefinedBenefitPlanRealEstateMember us-gaap:FairValueInputsLevel2Member country:US 2018-12-31 0001163165 us-gaap:FairValueInputsLevel1Member country:US 2018-12-31 0001163165 us-gaap:FairValueInputsLevel2Member country:US 2018-12-31 0001163165 us-gaap:FairValueInputsLevel3Member country:US 2018-12-31 0001163165 us-gaap:DefinedBenefitPlanEquitySecuritiesUsMember us-gaap:FairValueInputsLevel1Member us-gaap:ForeignPlanMember 2018-12-31 0001163165 us-gaap:DefinedBenefitPlanEquitySecuritiesUsMember us-gaap:FairValueInputsLevel2Member us-gaap:ForeignPlanMember 2018-12-31 0001163165 us-gaap:DefinedBenefitPlanEquitySecuritiesUsMember us-gaap:FairValueInputsLevel3Member us-gaap:ForeignPlanMember 2018-12-31 0001163165 us-gaap:DefinedBenefitPlanEquitySecuritiesNonUsMember us-gaap:FairValueInputsLevel1Member us-gaap:ForeignPlanMember 2018-12-31 0001163165 us-gaap:DefinedBenefitPlanEquitySecuritiesNonUsMember us-gaap:FairValueInputsLevel2Member us-gaap:ForeignPlanMember 2018-12-31 0001163165 us-gaap:DefinedBenefitPlanEquitySecuritiesNonUsMember us-gaap:FairValueInputsLevel3Member us-gaap:ForeignPlanMember 2018-12-31 0001163165 us-gaap:EquityFundsMember us-gaap:FairValueInputsLevel1Member us-gaap:ForeignPlanMember 2018-12-31 0001163165 us-gaap:EquityFundsMember us-gaap:FairValueInputsLevel2Member us-gaap:ForeignPlanMember 2018-12-31 0001163165 us-gaap:EquityFundsMember us-gaap:FairValueInputsLevel3Member us-gaap:ForeignPlanMember 2018-12-31 0001163165 us-gaap:ForeignPlanMember us-gaap:USGovernmentDebtSecuritiesMember 2018-12-31 0001163165 us-gaap:DomesticCorporateDebtSecuritiesMember us-gaap:ForeignPlanMember 2018-12-31 0001163165 us-gaap:ForeignPlanMember us-gaap:MutualFundMember 2018-12-31 0001163165 us-gaap:DefinedBenefitPlanCashAndCashEquivalentsMember us-gaap:ForeignPlanMember 2018-12-31 0001163165 us-gaap:ForeignPlanMember 2018-12-31 0001163165 us-gaap:PortionAtOtherThanFairValueFairValueDisclosureMember country:US cop:DefinedBenefitPlanCommonCollectiveTrustEquitySecuritiesMember 2018-12-31 0001163165 us-gaap:DefinedBenefitPlanCommonCollectiveTrustMember us-gaap:PortionAtOtherThanFairValueFairValueDisclosureMember country:US 2018-12-31 0001163165 us-gaap:DefinedBenefitPlanCashAndCashEquivalentsMember us-gaap:PortionAtOtherThanFairValueFairValueDisclosureMember country:US 2018-12-31 0001163165 us-gaap:DefinedBenefitPlanRealEstateMember us-gaap:PortionAtOtherThanFairValueFairValueDisclosureMember country:US 2018-12-31 0001163165 us-gaap:FairValueDisclosureItemAmountsDomain us-gaap:ForeignPlanMember 2019-12-31 0001163165 us-gaap:BankTimeDepositsMember us-gaap:FairValueInputsLevel1Member country:US 2018-12-31 0001163165 us-gaap:BankTimeDepositsMember us-gaap:FairValueInputsLevel2Member country:US 2018-12-31 0001163165 us-gaap:BankTimeDepositsMember us-gaap:FairValueInputsLevel3Member country:US 2018-12-31 0001163165 us-gaap:BankTimeDepositsMember us-gaap:ForeignPlanMember 2018-12-31 0001163165 cop:LowerFortyEightSegmentMember cop:PhysicalGasContractsMember 2017-01-01 2017-12-31 0001163165 cop:CanadaSegmentMember cop:PhysicalGasContractsMember 2017-01-01 2017-12-31 0001163165 cop:PhysicalGasContractsMember cop:EuropeMiddleEastAndNorthAfricaSegmentMember 2017-01-01 2017-12-31 0001163165 us-gaap:OtherNoncurrentAssetsMember country:US 2019-12-31 0001163165 srt:MinimumMember cop:MarineTerminalRevenueRefundingBondsMember cop:VariableRateDebtBondsMember 2019-12-31 0001163165 srt:MaximumMember cop:MarineTerminalRevenueRefundingBondsMember cop:VariableRateDebtBondsMember 2019-12-31 0001163165 srt:MinimumMember cop:MarineTerminalRevenueRefundingBondsMember cop:VariableRateDebtBondsMember 2018-12-31 0001163165 srt:MaximumMember cop:MarineTerminalRevenueRefundingBondsMember cop:VariableRateDebtBondsMember 2018-12-31 0001163165 cop:OtherAccruals1Member 2019-12-31 0001163165 cop:ShortTermDebt1Member 2019-12-31 0001163165 us-gaap:CashMember 2019-12-31 0001163165 cop:LongTermDebtLocationMember 2019-12-31 0001163165 cop:OtherLiabilitiesAndDeferredCreditsMember 2019-12-31 0001163165 country:US cop:IncentiveStockOptionsMember 2019-12-31 0001163165 us-gaap:OperatingSegmentsMember cop:LowerFortyEightSegmentMember cop:NiobraraMember 2019-12-02 0001163165 us-gaap:QualifiedPlanMember country:US cop:PrudentialBenefitObligationMember 2018-01-01 2018-12-31 0001163165 us-gaap:AssetRetirementObligationCostsMember us-gaap:OperatingSegmentsMember cop:LowerFortyEightSegmentMember cop:NiobraraMember 2019-12-02 0001163165 us-gaap:OtherNoncurrentAssetsMember 2018-12-31 0001163165 us-gaap:OtherNoncurrentLiabilitiesMember 2018-12-31 0001163165 us-gaap:OtherNoncurrentAssetsMember 2019-12-31 0001163165 us-gaap:OtherNoncurrentLiabilitiesMember 2019-12-31 0001163165 us-gaap:EquityMethodInvestmentNonconsolidatedInvesteeOrGroupOfInvesteesMember 2019-12-31 0001163165 us-gaap:EquityMethodInvestmentNonconsolidatedInvesteeOrGroupOfInvesteesMember 2018-12-18 0001163165 us-gaap:EquityMethodInvestmentNonconsolidatedInvesteeOrGroupOfInvesteesMember 2019-01-01 2019-12-31 0001163165 us-gaap:EquityMethodInvestmentNonconsolidatedInvesteeOrGroupOfInvesteesMember 2018-01-01 2018-12-31 0001163165 us-gaap:EquityMethodInvestmentNonconsolidatedInvesteeOrGroupOfInvesteesMember 2017-01-01 2017-12-31 0001163165 us-gaap:PrepaidExpensesAndOtherCurrentAssetsMember srt:RestatementAdjustmentMember 2019-12-31 0001163165 us-gaap:OtherAssetsMember srt:RestatementAdjustmentMember 2019-12-31 0001163165 us-gaap:OtherAssetsMember srt:RestatementAdjustmentMember 2018-12-31 0001163165 us-gaap:AccumulatedOtherComprehensiveIncomeMember srt:CumulativeEffectPeriodOfAdoptionAdjustmentMember 2018-12-31 0001163165 us-gaap:RetainedEarningsMember srt:CumulativeEffectPeriodOfAdoptionAdjustmentMember 2018-12-31 0001163165 us-gaap:AccumulatedOtherComprehensiveIncomeMember srt:CumulativeEffectPeriodOfAdoptionAdjustmentMember 2019-12-31 0001163165 us-gaap:RetainedEarningsMember srt:CumulativeEffectPeriodOfAdoptionAdjustmentMember 2019-12-31 0001163165 srt:CumulativeEffectPeriodOfAdoptionAdjustmentMember 2018-12-31 0001163165 srt:CumulativeEffectPeriodOfAdoptionAdjustmentMember 2019-12-31 0001163165 us-gaap:AccountingStandardsUpdate201802Member 2019-12-31 0001163165 us-gaap:OtherPostretirementBenefitPlansDefinedBenefitMember us-gaap:QualifiedPlanMember country:US cop:CopPreSixtyFiveRetireeMember cop:PrudentialBenefitObligationMember 2019-01-01 2019-12-31 0001163165 us-gaap:OtherPostretirementBenefitPlansDefinedBenefitMember us-gaap:QualifiedPlanMember country:US cop:PostSixtyFiveRetireeMember cop:PrudentialBenefitObligationMember 2019-01-01 2019-12-31 0001163165 us-gaap:AllowanceForNotesReceivableMember 2018-12-31 0001163165 us-gaap:AllowanceForNotesReceivableMember 2019-01-01 2019-12-31 0001163165 us-gaap:AllowanceForNotesReceivableMember 2019-12-31 0001163165 us-gaap:ValuationAllowanceOfDeferredTaxAssetsMember 2018-12-31 0001163165 us-gaap:ValuationAllowanceOfDeferredTaxAssetsMember 2019-01-01 2019-12-31 0001163165 us-gaap:ValuationAllowanceOfDeferredTaxAssetsMember 2019-12-31 0001163165 us-gaap:BusinessRestructuringReservesMember 2018-12-31 0001163165 us-gaap:BusinessRestructuringReservesMember 2019-01-01 2019-12-31 0001163165 us-gaap:BusinessRestructuringReservesMember 2019-12-31 0001163165 us-gaap:AllowanceForNotesReceivableMember 2017-12-31 0001163165 us-gaap:AllowanceForNotesReceivableMember 2018-01-01 2018-12-31 0001163165 us-gaap:ValuationAllowanceOfDeferredTaxAssetsMember 2017-12-31 0001163165 us-gaap:ValuationAllowanceOfDeferredTaxAssetsMember 2018-01-01 2018-12-31 0001163165 us-gaap:BusinessRestructuringReservesMember 2017-12-31 0001163165 us-gaap:BusinessRestructuringReservesMember 2018-01-01 2018-12-31 0001163165 us-gaap:AllowanceForNotesReceivableMember 2016-12-31 0001163165 us-gaap:AllowanceForNotesReceivableMember 2017-01-01 2017-12-31 0001163165 us-gaap:ValuationAllowanceOfDeferredTaxAssetsMember 2016-12-31 0001163165 us-gaap:ValuationAllowanceOfDeferredTaxAssetsMember 2017-01-01 2017-12-31 0001163165 us-gaap:BusinessRestructuringReservesMember 2016-12-31 0001163165 us-gaap:BusinessRestructuringReservesMember 2017-01-01 2017-12-31 iso4217:CAD iso4217:GBP iso4217:USD xbrli:pure xbrli:shares utr:Bcfe iso4217:USD xbrli:shares
1
 
PART
 
I
 
 
Unless otherwise indicated, “the company,” “we,” “our,” “us” and “ConocoPhillips” are used in
 
this report to
refer to the businesses of ConocoPhillips and its consolidated
 
subsidiaries.
 
Items 1 and 2—Business and
Properties, contain forward-looking statements including,
 
without limitation, statements relating to our plans,
strategies, objectives, expectations and intentions
 
that are made pursuant to the “safe harbor”
 
provisions of the
Private Securities Litigation Reform Act of 1995.
 
The words “anticipate,” “estimate,” “believe,”
 
“budget,”
“continue,” “could,” “intend,” “may,” “plan,” “potential,” “predict,” “seek,” “should,”
 
“will,” “would,”
“expect,” “objective,” “projection,” “forecast,” “goal,”
 
“guidance,” “outlook,” “effort,” “target” and similar
expressions identify forward-looking statements.
 
The company does not undertake to update,
 
revise or correct
any forward-looking information unless required to do so under
 
the federal securities laws.
 
Readers are
cautioned that such forward-looking statements should
 
be read in conjunction with the company’s disclosures
under the headings “Risk Factors” beginning on page
 
21 in our 2019 Annual Report on Form 10-K
 
and
“CAUTIONARY STATEMENT
 
FOR THE PURPOSES OF THE ‘SAFE HARBOR’
 
PROVISIONS OF THE
PRIVATE
 
SECURITIES LITIGATION REFORM ACT OF 1995,” beginning on page 60.
 
 
 
Items 1 and 2.
 
BUSINESS AND PROPERTIES
 
 
CORPORATE STRUCTURE
 
ConocoPhillips is an independent E&P company with
 
operations and activities in 17 countries.
 
Our diverse,
low cost of supply portfolio includes resource-rich unconventional
 
plays in North America; conventional
assets in North America, Europe, Asia and Australia;
 
LNG developments; oil sands assets in Canada;
 
and an
inventory of global conventional and unconventional exploration
 
prospects.
 
Headquartered in Houston, Texas,
at December 31, 2019, we employed approximately
 
10,400 people worldwide and had total assets
 
of $71
billion.
 
 
ConocoPhillips was incorporated in the state of
 
Delaware on November 16, 2001, in connection with, and
 
in
anticipation of, the merger between Conoco Inc. and Phillips
 
Petroleum Company.
 
The merger between
Conoco and Phillips was consummated on August
 
30, 2002.
 
 
 
SEGMENT AND GEOGRAPHIC INFORMATION
 
We
 
manage our operations through six operating
 
segments, defined by geographic region: Alaska;
 
Lower 48;
Canada; Europe, Middle East and North Africa; Asia Pacific
 
and Other International.
 
Effective with the third
quarter of 2020, we have restructured our segments to align
 
with changes to our internal organization.
 
The
Middle East business was realigned from the Asia Pacific
 
and Middle East segment to the Europe and North
Africa segment.
 
The segments have been renamed the Asia
 
Pacific segment and the Europe, Middle East and
North Africa segment.
 
We have revised segment information disclosures and segment performance metrics
presented within our results of operations for the current
 
and prior years.
 
For operating segment and
geographic information, see Note 25—Segment Disclosures
 
and Related Information, in the Notes to
Consolidated Financial Statements, which is incorporated
 
herein by reference.
 
 
We
 
explore for, produce, transport and market crude oil, bitumen,
 
natural gas, LNG and NGLs on a worldwide
basis.
 
At December 31, 2019, our operations were producing
 
in the U.S., Norway, Canada, Australia, Timor-
Leste, Indonesia, Malaysia, Libya, China and Qatar.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2
 
The information listed below appears in the “Oil and
 
Gas Operations” disclosures following the
 
Notes to
Consolidated Financial Statements and is incorporated
 
herein by reference:
 
●
 
Proved worldwide crude oil, NGLs,
 
natural gas and bitumen reserves.
●
 
Net production of crude oil, NGLs,
 
natural gas and bitumen.
●
 
Average sales prices of crude oil, NGLs,
 
natural gas and bitumen.
●
 
Average production costs per BOE.
●
 
Net wells completed, wells in progress and productive
 
wells.
●
 
Developed and undeveloped acreage.
 
The following table is a summary of the proved
 
reserves information included in the “Oil and Gas Operations”
disclosures following the Notes to Consolidated
 
Financial Statements.
 
Approximately 80 percent of our
proved reserves are located in politically stable
 
countries that belong to the Organization for Economic
Cooperation and Development.
 
Natural gas reserves are converted to BOE based on a
 
6:1 ratio: six MCF of
natural gas converts to one BOE.
 
See Management’s Discussion and Analysis of Financial Condition and
Results of Operations for a discussion of factors that
 
will enhance the understanding of the following
 
summary
reserves table.
 
 
Millions of Barrels of Oil Equivalent
Net Proved Reserves at December 31
2019
2018
2017
Crude oil
Consolidated operations
2,562
2,533
2,322
Equity affiliates
73
78
83
Total Crude Oil
2,635
2,611
2,405
Natural gas liquids
Consolidated operations
361
349
354
Equity affiliates
39
42
45
Total Natural Gas Liquids
400
391
399
Natural gas
Consolidated operations
1,209
1,265
1,267
Equity affiliates
736
760
717
Total Natural Gas
1,945
2,025
1,984
Bitumen
Consolidated operations
282
236
250
Total Bitumen
282
236
250
Total consolidated operations
4,414
4,383
4,193
Total equity affiliates
848
880
845
Total company
5,262
5,263
5,038
 
 
Total production of 1,348 MBOED increased 5 percent in 2019 compared with 2018.
 
 
The increase in total
average production primarily resulted from new wells
 
online in the Lower 48;
 
an increased interest in the
Western North Slope (WNS) and Greater Kuparuk Area (GKA) of Alaska following acquisitions
 
closed in
2018; and higher production in Norway due to drilling
 
activity and the startup of Aasta Hansteen
 
in December
2018.
 
The increase in production was partly offset by normal
 
field decline and disposition impacts,
 
primarily
from the U.K. asset sale in 2019 and non-core asset sales
 
in the Lower 48 during 2018.
 
 
Production excluding Libya was 1,305 MBOED in
 
2019 compared with 1,242 MBOED in 2018,
 
an increase of
63 MBOED or 5 percent.
 
Underlying production, which excludes Libya and
 
the net volume impact from
 
 
 
 
 
 
 
 
 
 
 
 
 
3
 
closed dispositions and acquisitions of 51 MBOED in 2019
 
and 47 MBOED in 2018, is used to measure our
ability to grow production organically.
 
Our underlying production grew 5 percent to 1,254
 
MBOED in 2019
from 1,195 MBOED in 2018.
 
Our worldwide annual average realized price was
 
$48.78 per BOE in 2019, a decrease of 9 percent
 
compared
with $53.88 per BOE in 2018, reflecting weaker marker
 
prices as a result of macroeconomic demand
 
concerns.
 
Our worldwide annual average crude oil price decreased
 
10 percent, from $68.13 per barrel in 2018 to $60.99
per barrel in 2019.
 
Additionally, our worldwide annual average NGL prices decreased
 
34 percent, from
$30.48 per barrel in 2018 to $20.09 per barrel in
 
2019.
 
Our worldwide annual average natural gas
 
price
decreased 11 percent, from $5.65 per MCF in 2018 to $5.03 per
 
MCF in 2019.
 
Average annual bitumen prices
increased 42 percent, from $22.29 per barrel in 2018 to
 
$31.72 per barrel in 2019.
 
 
ALASKA
 
The Alaska segment primarily explores for, produces, transports and markets
 
crude oil, natural gas and NGLs.
 
We
 
are the largest crude oil producer in Alaska and have
 
major ownership interests in two of North America’s
largest oil fields located on Alaska’s North Slope: Prudhoe Bay and Kuparuk.
 
We also have a 100 percent
interest in the Alpine Field, located on the Western North Slope.
 
Additionally, we are one of Alaska’s largest
owners of state, federal and fee exploration leases, with
 
approximately 1.32 million net undeveloped acres at
year-end 2019.
 
Alaska operations contributed 25 percent of
 
our consolidated liquids production and less than
1 percent of our natural gas production.
 
 
2019
Interest
Operator
Liquids
MBD
Natural Gas
MMCFD
Total
MBOED
Average Daily Net Production
Greater Prudhoe Area
36.1
%
BP
81
4
81
Greater Kuparuk Area
91.4-94.7
ConocoPhillips
86
2
86
Western North Slope
100.0
ConocoPhillips
50
1
51
Total Alaska
217
7
218
 
 
Greater Prudhoe Area
The Greater Prudhoe Area includes the Prudhoe
 
Bay Field and five satellite fields, as well
 
as the Greater Point
McIntyre Area fields.
 
Prudhoe Bay, the largest oil field on Alaska’s North Slope, is the site of a large
waterflood and enhanced oil recovery operation, as well
 
as a gas plant which processes natural gas to recover
NGLs before reinjection into the reservoir.
 
Prudhoe Bay’s satellites are Aurora, Borealis, Polaris, Midnight
Sun and Orion, while the Point McIntyre, Niakuk,
 
Raven, Lisburne and North Prudhoe Bay State fields
 
are
part of the Greater Point McIntyre Area.
 
 
Greater Kuparuk Area
We
 
operate the Greater Kuparuk Area, which
 
consists of the Kuparuk Field and four satellite
 
fields: Tarn,
Tabasco, Meltwater and West
 
Sak.
 
Kuparuk is located 40 miles west of Prudhoe Bay.
 
Field installations
include three central production facilities which separate
 
oil, natural gas and water, as well as a separate
seawater treatment plant.
 
Development drilling at Kuparuk
 
consists of rotary-drilled wells and horizontal
multi-laterals from existing well bores utilizing
 
coiled-tubing drilling.
 
Western North Slope
On the Western North Slope, we operate the Colville River Unit, which includes the
 
Alpine Field and three
satellite fields: Nanuq, Fiord and Qannik.
 
Alpine is located 34 miles west of Kuparuk.
 
In 2015, first oil was
achieved at Alpine West CD5,
 
a drill site which extends the Alpine reservoir west into
 
the National Petroleum
Reserve-Alaska (NPR-A).
 
In 2019, we continued drilling additional wells
 
using the
 
available well slots on this
pad.
 
 
 
 
4
 
The Greater Mooses Tooth Unit, the first unit established entirely within the NPR-A, was
 
formed in 2008.
 
In
2017, we began construction in the unit with two
 
drill sites; Greater Mooses Tooth #1 (GMT-1) and Greater
Mooses Tooth #2 (GMT-2).
 
GMT-1 achieved first oil in the fourth
 
quarter of 2018 and completed drilling
 
in
2019.
 
We expect first oil from GMT-2 in 2021.
 
 
Alaska North Slope Gas
In 2016, we, along with affiliates of Exxon Mobil Corporation,
 
BP p.l.c. and Alaska Gasline Development
Corporation (AGDC), a state-owned corporation, completed
 
preliminary FEED technical work for a potential
LNG project which would liquefy and export natural
 
gas from Alaska’s North Slope and deliver it to
market.
 
In 2016, we, along with the affiliates of ExxonMobil
 
and BP,
 
indicated our intention not to progress
into the next phase of the project due to changes in the
 
economic environment.
 
AGDC decided to continue on
its own.
 
In 2019, affiliates of ExxonMobil and BP agreed
 
to each contribute up to $5 million or approximately
one third of
 
AGDC’s anticipated costs for full-year 2020.
 
In 2020, AGDC will be focused on permitting
efforts, the most important of which is the National Environmental
 
Protection Act process before the FERC.
 
FERC’s final milestones are the Publication of Notice of Availability of Final Environmental Impact
Statement, which is scheduled for March 6, 2020, and the
 
Issuance of Final Order, which is scheduled for June
4, 2020.
 
AGDC has recently contracted with Fluor
 
Corporation to evaluate cost reduction opportunities
 
in
preparation for soliciting partners for the project.
 
We
 
continue to be willing to sell our North Slope gas to
 
the
project but do not plan to take an equity position.
 
 
Exploration
Appraisal of the Willow Discovery, located in the northeast portion of the NPR-A, continued throughout
 
2019
with five appraisal wells.
 
In 2020, we will continue appraisal of the Willow Discovery and
 
explore the
Harpoon Prospect, located southwest of Willow.
 
In 2019, we drilled the West Willow-2 well to appraise the 2018 West Willow oil discovery.
 
 
In late 2018, we commenced appraisal of the Putu Discovery
 
with a long reach well from existing Alpine CD4
infrastructure.
 
The CD4 appraisal well finished drilling and
 
flow tested in 2019.
 
A supporting injector well
was drilled in late 2019 for a 2020 injectivity test.
 
The Cairn 2S-315 Well was drilled in late 2018 from the 2S drill site on state leases in the
 
Kuparuk River Unit.
 
A long-term flow test was commenced in 2019 and
 
evaluations are ongoing.
 
 
A 3-D
 
seismic survey was completed in 2018 over a 250-mile
 
area on state lands.
 
We are currently evaluating
this seismic data for future exploration opportunities.
 
We
 
were successful in the federal lease sale on the
 
North Slope in the fourth quarter of 2019,
 
where we were
the high bidder on three tracts for a total of approximately
 
33,000 net acres.
 
 
Acquisitions
In the third quarter of 2019, we completed the Nuna
 
discovery acreage acquisition, expanding the
 
Kuparuk
River Unit by 21,000 acres and leveraging legacy
 
infrastructure.
 
Transportation
We
 
transport the petroleum liquids produced
 
on the North Slope to south central Alaska through an
 
800-mile
pipeline that is part of Trans-Alaska Pipeline System (TAPS).
 
We
 
have a 29.1 percent ownership interest
 
in
TAPS, and we also have ownership interests in the Alpine, Kuparuk and Oliktok pipelines
 
on the North Slope.
 
Our wholly owned subsidiary, Polar Tankers, Inc., manages the marine transportation of our North Slope
production, using five company-owned, double-hulled
 
tankers, and charters third-party vessels as necessary.
 
The tankers deliver oil from Valdez, Alaska, primarily to refineries on the west coast of the U.S.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
5
 
LOWER 48
 
The Lower 48 segment consists of operations located
 
in the contiguous U.S.
 
and the Gulf of Mexico.
 
Organized into the Gulf Coast and Great Plains business units,
 
we hold 10.4
 
million net onshore and offshore
acres,
 
with a portfolio of conventional production
 
from legacy assets as well as newer production
 
from our low
cost of supply, shorter cycle time, resource-rich unconventional plays.
 
Based on 2019 production volumes,
 
the
Lower 48 is the company’s largest segment and contributed 41 percent of our consolidated liquids
 
production
and 35 percent of our natural gas production.
 
 
2019
Interest
Operator
Liquids
MBD
Natural Gas
MMCFD
Total
MBOED
Average Daily Net Production
Eagle Ford
Various
%
Various
174
251
216
Gulf of Mexico
Various
Various
15
11
16
Gulf Coast—Other
Various
Various
3
9
5
 
Total Gulf Coast
192
271
237
Bakken
Various
Various
82
92
97
Permian Unconventional
Various
Various
40
94
56
Permian Conventional
Various
Various
20
59
30
Anadarko Basin
Various
Various
5
58
14
Wyoming/Uinta
Various
Various
-
36
6
Niobrara*
Various
Various
8
12
11
 
Total Great Plains
155
351
214
Total Lower 48
347
622
451
*Classified as held-for-sale
 
as of December 31, 2019.
 
See 'Dispositions' below for additional
 
information.
 
 
Onshore
We
 
hold 10.3 million net acres of onshore
 
conventional and unconventional acreage
 
in the Lower 48, the
majority of which is either held by production or owned
 
by the company.
 
Our unconventional holdings total
approximately 1.7 million net acres in the following
 
areas:
 
 
●
 
610,000 net acres in the Bakken, located in North
 
Dakota and eastern Montana.
 
●
 
234,000 net acres in Central Louisiana, where we recently
 
announced our intention to discontinue
exploration activities.
●
 
201,000 net acres in the Eagle Ford, located in South Texas.
 
●
 
167,000 net acres in the Permian, located in West Texas and southeastern New Mexico.
●
 
98,000 net acres in the Niobrara, located in northeastern
 
Colorado.
 
●
 
363,000 net acres in other areas with unconventional
 
potential.
 
The majority of our 2019
 
onshore production originated from
 
the Big 3—Eagle Ford, Bakken and Permian
Unconventional.
 
Onshore activities in 2019 were centered
 
mostly on continued development of assets, with an
emphasis on areas with low cost of supply, particularly in growing unconventional
 
plays.
 
Our major focus
areas in 2019
 
included the following:
 
 
●
 
Eagle Ford—The Eagle Ford continued full-field development
 
in 2019.
 
We operated seven rigs on
average in 2019, resulting in 155 operated wells
 
drilled and 166 operated wells brought online.
 
Production increased 16 percent in 2019 compared with
 
2018, averaging 216 MBOED and 186
MBOED, respectively.
 
●
 
Bakken—We operated an average of three rigs during the year in the Bakken and participated
 
in
additional development activities operated by co-venturers.
 
We continued our pad drilling with 62
 
 
 
6
 
operated wells drilled during the year and 44 operated
 
wells brought online.
 
Production increased 15
percent in 2019 compared with 2018, averaging 97 MBOED
 
and 84 MBOED, respectively.
 
●
 
Permian Basin—The Permian Basin is a combination
 
of legacy conventional and unconventional
assets.
 
We operated an average of three rigs during the year in the Permian Basin, resulting
 
in 29
operated wells drilled and 35 operated wells brought
 
online.
 
The Permian Basin produced 86
MBOED in 2019, increasing 30 percent compared with
 
2018, including 56 MBOED of
unconventional production.
 
Gulf of Mexico
At year-end 2019, our portfolio of producing properties
 
in the Gulf of Mexico totaled approximately 60,000
net acres.
 
A majority of the production consists of three
 
fields operated by co-venturers:
 
●
 
15.9 percent nonoperated working interest in the unitized
 
Ursa Field located in the Mississippi Canyon
Area.
●
 
15.9 percent nonoperated working interest in the Princess
 
Field, a northern subsalt extension of the
Ursa Field.
●
 
12.4 percent nonoperated working interest in the unitized
 
K2 Field, comprised of seven blocks in the
Green Canyon Area.
 
Dispositions
We
 
have terminal and pipeline use agreements
 
with Golden Pass LNG Terminal and affiliated Golden Pass
Pipeline near Sabine Pass, Texas, intended to provide us with terminal and
 
pipeline capacity for the receipt,
storage and regasification of LNG purchased from Qatar
 
Liquefied Gas Company Limited (3) (QG3).
 
We
previously held a 12.4 percent interest in Golden Pass
 
LNG Terminal and Golden Pass Pipeline, but we sold
those interests in the second quarter of 2019 while
 
retaining the basic use agreements.
 
In the fourth quarter of 2019, we
 
completed the sale of our interests in the Magnolia Field in
 
the Gulf of
Mexico.
 
Production from this disposed asset was less than
 
one MBOED in 2019.
 
In the fourth quarter of 2019, we entered into an agreement
 
to sell our interests in the Niobrara, with an
anticipated closing date in the first quarter of 2020.
 
Production from the interests to be disposed was
approximately 11 MBOED in 2019.
 
In January 2020, we entered into an agreement
 
to sell our interests in certain non-core properties
 
for $186
million, plus customary adjustments.
 
The assets met the held for sale criteria in January
 
2020 and the
transaction is expected to be completed in the first
 
quarter of 2020.
 
This disposition will not have a significant
impact on Lower 48 production.
 
 
For additional information on these transactions,
 
see Note 5—Asset Acquisitions and Dispositions,
 
in the
Notes to Consolidated Financial Statements.
 
Exploration
 
Our exploration focus is on onshore unconventional plays,
 
which in 2019 included the Delaware in the
Permian Basin, and the Eagle Ford in south Texas.
 
In the third quarter of 2019, we announced
 
our decision to
discontinue exploration activities in the Central Louisiana
 
Austin Chalk.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
7
 
Facilities
 
●
 
Lost Cabin Gas Plant—We operate and own a 46 percent interest in the Lost Cabin
 
Gas Plant, a 246
MMCFD capacity natural gas processing facility in
 
Lysite, Wyoming.
 
The plant is currently operating at
less than capacity due to a fire in December 2018.
 
Restoration efforts are ongoing and anticipated to be
completed in the second half of 2020.
 
The expected production loss in 2020 is immaterial
 
to the segment.
●
 
Helena Condensate Processing Facility—We operate and own the Helena Condensate
 
Processing Facility,
a 110 MBD condensate processing plant located in Kenedy, Texas.
 
●
 
Sugarloaf Condensate Processing Facility—We operate and own an 87.5 percent interest in the
 
Sugarloaf
Condensate Processing Facility, a 30 MBD condensate processing plant located
 
near Pawnee, Texas.
●
 
Bordovsky Condensate Processing Facility—We operate and own the Bordovsky Condensate
 
Processing
Facility, a 15 MBD condensate processing plant located in Kenedy, Texas.
 
 
CANADA
 
Our Canadian operations mainly consist of the Surmont
 
oil sands development in Alberta and the liquids-rich
Montney unconventional play in British Columbia.
 
In 2019, operations in Canada contributed
 
7 percent of our
consolidated liquids production and less than 1 percent
 
of our natural gas production.
 
2019
Liquids
Natural Gas
Bitumen
Total
Interest
Operator
MBD
MMCFD
MBD
MBOED
Average Daily Net Production
Surmont
50.0
%
ConocoPhillips
-
-
60
60
Montney
100.0
ConocoPhillips
1
9
-
3
Total Canada
1
9
60
63
 
 
Surmont
Our bitumen resources in Canada are produced via an
 
enhanced thermal oil recovery method called SAGD,
whereby steam is injected into the reservoir, effectively liquefying the heavy bitumen,
 
which is recovered and
pumped to the surface for further processing.
 
We
 
hold approximately 0.6 million net acres
 
of land in the
Athabasca Region of northeastern Alberta.
 
The Surmont oil sands leases are located approximately
 
35 miles south of Fort McMurray, Alberta.
 
Surmont
is a 50/50 joint venture with Total S.A.
 
The second phase of the Surmont Project achieved first
 
production in
2015 and reached peak production in 2018.
 
We are focused on structurally lowering costs, reducing GHG
intensity and optimizing asset performance.
 
 
The Alberta government imposed a production curtailment
 
impacting the industry beginning in January 2019.
 
The curtailment measure, which impacted our annualized
 
average production by 3 MBOED in 2019, is
intended to strengthen the WCS differential to WTI at Hardisty.
 
The curtailment program is established and
administered by the Alberta Energy Regulator under the
Curtailment Rules
 
regulation, which is currently set to
expire on December 31, 2020.
 
Montney
We
 
hold approximately 151,000 net acres
 
in the emerging unconventional Montney play in northeast
 
British
Columbia.
 
Our Montney activity in 2019 included drilling
 
16 horizontal wells, completing 14 horizontal wells
and acquiring approximately 6,000 additional net
 
acres.
 
Production from our 2019 drilling program
commenced in February 2020 following the completion
 
of third-party offtake facilities.
 
Appraisal drilling and completions activity will
 
continue in 2020 to further explore the area’s resource
potential.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
8
 
 
Exploration
 
Our primary exploration focus is assessing our
 
Montney onshore unconventional acreage in Western Canada.
 
Additionally, we have exploration acreage in the Mackenzie Delta/Beaufort Sea Region
 
and the Arctic Islands.
 
 
EUROPE, MIDDLE EAST AND NORTH AFRICA
 
The Europe,
 
Middle East and North Africa segment consisted
 
of operations in Norway, Qatar, Libya and the
U.K. and exploration activities in Norway and Libya.
 
In 2019, operations in Europe, Middle East
 
and North
Africa contributed 17 percent of our consolidated liquids
 
production and 27 percent of natural gas production.
 
 
Norway
2019
Liquids
Natural Gas
Total
Interest
Operator
MBD
MMCFD
MBOED
Average Daily Net Production
Greater Ekofisk Area
35.1
%
ConocoPhillips
50
44
57
Heidrun
24.0
Equinor
14
29
19
Alvheim
20.0
Aker BP
10
12
12
Visund
9.1
Equinor
4
46
12
Aasta Hansteen
10.0
Equinor
-
64
11
Troll
1.6
Equinor
2
49
10
Other
Various
Equinor
8
10
10
Total Norway
88
254
131
 
 
The Greater Ekofisk Area is located approximately 200
 
miles offshore Stavanger, Norway,
 
in the North Sea,
and comprises three producing fields: Ekofisk, Eldfisk and
 
Embla.
 
Crude oil is exported to Teesside, England,
and the natural gas is exported to Emden, Germany.
 
The Ekofisk and Eldfisk fields consist of
 
several
production platforms and facilities, including the
 
Ekofisk South and Eldfisk II
 
developments.
 
Continued
development drilling in the Greater Ekofisk Area is
 
expected to contribute additional production over the
coming years, as additional wells come online.
 
The Heidrun Field is located in the Norwegian Sea.
 
Produced crude oil is stored in a floating storage
 
unit and
exported via shuttle tankers.
 
Part of the natural gas is currently injected
 
into the reservoir for optimization
 
of
crude oil production,
 
some gas is transported for use as
 
feedstock in a methanol plant in Norway, in which we
own an 18 percent interest,
 
and the remainder is transported to Europe
 
via gas processing terminals in Norway.
 
The Alvheim Field is located in the northern part
 
of the North Sea near the border with the U.K. sector, and
consists of a FPSO vessel and subsea installations.
 
Produced crude oil is exported via shuttle tankers,
 
and
natural gas is transported to the Scottish Area Gas Evacuation
 
(SAGE) Terminal at St. Fergus, Scotland,
through the SAGE Pipeline.
 
Visund is an oil and gas field located in the North Sea and consists of a floating
 
drilling, production and
processing unit, and subsea installations.
 
Crude
 
oil is transported by pipeline to a nearby third-party
 
field for
storage and export via tankers.
 
The natural gas is transported to a gas processing plant
 
at Kollsnes, Norway,
through the Gassled transportation system.
 
Aasta Hansteen is located in the Norwegian Sea and
 
achieved first production in December 2018.
 
Produced
condensate is loaded onto shuttle tankers and transported
 
to market.
 
Gas is transported through the Polarled
gas pipeline to the onshore Nyhamna processing plant
 
for final processing prior to export to market.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
9
 
The Troll Field lies in the northern part of the North Sea and consists of the
 
Troll A, B and C platforms.
 
The
natural gas from Troll A is transported to Kollsnes, Norway.
 
Crude oil from floating platforms Troll B and
Troll C is transported to Mongstad, Norway, for storage and export.
 
We
 
also have varying ownership interests in two
 
other producing fields in the Norway sector of the
 
North Sea.
 
Exploration
 
In 2019, we operated the Busta and Enniberg exploration wells
 
in Block 25/7 in the North Sea.
 
The Busta well
encountered hydrocarbons and will be evaluated for
 
future appraisal consideration.
 
The Enniberg well
encountered insufficient hydrocarbons and was expensed as
 
a dry hole in 2019.
 
We also participated in the
Canela exploration well in the Heidrun area of the Norwegian
 
Sea.
 
The well encountered hydrocarbons and
will be further evaluated to determine commerciality.
 
In 2019, we were awarded two new exploration
licenses; PL1001 and PL1009; and one acreage
 
addition, PL782SD.
 
Transportation
We
 
own a 35.1 percent interest in the Norpipe
 
Oil Pipeline System, a 220-mile pipeline which
 
carries crude oil
from Ekofisk to a crude oil stabilization and NGLs processing
 
facility in Teesside, England.
 
United Kingdom
2019
Natural
Liquids
 
Gas
Total
Interest
Operator
MBD
MMCFD
MBOED
Average Daily Net Production
Britannia Satellites*
26.3–93.8
%
ConocoPhillips
7
55
16
J-Area
32.5–36.5
ConocoPhillips
6
38
12
Britannia
58.7
ConocoPhillips
2
49
10
East Irish Sea
100.0
Spirit Energy
-
48
8
Clair
7.5
BP
4
1
4
Other
Various
Various
-
2
-
Total United Kingdom
19
193
50
*Includes the Chevron
 
-operated Alder Field, ConocoPhillips equity
 
interest was 26.3
 
percent.
 
 
On September 30, 2019, we completed the sale of
 
two ConocoPhillips U.K. subsidiaries to Chrysaor
 
E&P
Limited, including all of our producing assets in the
 
U.K.
 
Annualized average production from the assets sold
was 50 MBOED in 2019.
 
For additional information on this transaction, see
 
Note 5—Asset Acquisitions and
Dispositions, in the Notes to Consolidated Financial
 
Statements.
 
 
We
 
retained our Teesside, England oil terminal, where we are the operator and
 
have a 40.25 percent ownership
interest, to support
 
our Norway operations.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
10
 
Qatar
2019
Natural
Liquids
Gas
Total
Interest
Operator
MBD
MMCFD
MBOED
Average Daily Net Production
Qatargas Operating
QG3
30.0
%
Company Limited
21
373
83
Total Qatar
21
373
83
 
 
QG3 is an integrated development jointly owned by
 
Qatar Petroleum (68.5 percent), ConocoPhillips
(30 percent) and Mitsui & Co., Ltd. (1.5 percent).
 
QG3 consists of upstream natural gas production
 
facilities,
which produce approximately 1.4 billion gross cubic feet
 
per day of natural gas from Qatar’s North Field over
a 25-year life, in addition to a 7.8 million gross tonnes-per-year
 
LNG facility.
 
LNG is shipped in leased LNG
carriers destined for sale globally.
 
 
QG3 executed the development of the onshore and offshore assets
 
as a single integrated development with
Qatargas 4 (QG4), a joint venture between Qatar Petroleum
 
and Royal Dutch Shell plc.
 
This included the joint
development of offshore facilities situated in a common offshore block in
 
the North Field, as well as the
construction of two identical LNG process trains and
 
associated gas treating facilities for both the QG3
 
and
QG4 joint ventures.
 
Production from the LNG trains and associated
 
facilities is combined and shared.
 
 
Libya
2019
Natural
Liquids
Gas
Total
Interest
Operator
MBD
MMCFD
MBOED
Average Daily Net Production
Waha Concession
16.3
%
Waha Oil Co.
38
31
43
Total Libya
38
31
43
 
 
The Waha Concession consists of multiple concessions and encompasses nearly 13 million
 
gross acres in the
Sirte Basin.
 
Our production operations in Libya
 
and related oil exports have periodically been interrupted
 
over
the last several years due to the shutdown of the
 
Es Sider crude oil export terminal.
 
In 2019, we had 19 crude
liftings from Es Sider.
 
The number of crude liftings from the Es Sider
 
crude oil export terminal in 2020 is
uncertain due to civil unrest.
 
In January 2020, we declared Force Majeure
 
to our crude shippers following the
blockade of the Es Sider crude oil export terminal
 
and the declaration of Force Majeure by the National
 
Oil
Corporation of Libya.
 
 
ASIA PACIFIC
 
The Asia Pacific segment has exploration and production
 
operations in China, Indonesia, Malaysia and
Australia and producing operations in Timor-Leste.
 
In 2019, operations in the Asia Pacific segment
contributed 10 percent of our consolidated liquids production
 
and 36 percent of natural gas production.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
11
 
Australia and Timor-Leste
2019
Natural
Liquids
 
Gas
Total
Interest
Operator
MBD
MMCFD
MBOED
Average Daily Net Production
ConocoPhillips/
Australia Pacific LNG
37.5
%
Origin Energy
-
679
113
Bayu-Undan*
56.9
ConocoPhillips
10
194
43
Athena/Perseus*
50.0
ExxonMobil
-
31
5
Total Australia and Timor-Leste
10
904
161
*This asset is held-for-sale as of December
 
31, 2019.
 
See Note 5—Asset Acquisitions
 
and Dispositions, in the Notes to Consolidated
 
Financial
Statements, for additional
 
information.
 
 
Australia Pacific LNG
Australia Pacific LNG Pty Ltd (APLNG), our joint venture
 
with Origin Energy Limited and China
Petrochemical Corporation (Sinopec), is focused
 
on producing CBM from the Bowen and Surat basins
 
in
Queensland, Australia, to supply the domestic gas market
 
and convert the CBM into LNG for export.
 
Origin
operates APLNG’s upstream production and pipeline system, and we operate the
 
downstream LNG facility,
located on Curtis Island near Gladstone, Queensland,
 
as well as the LNG export sales business.
 
 
We
 
operate two fully subscribed 4.5-million-metric-tonnes-per-year
 
LNG trains.
 
Approximately 3,900 net
wells are ultimately expected to supply both the LNG
 
sales contracts and domestic gas market.
 
The wells are
supported by gathering systems, central gas processing
 
and compression stations, water treatment
 
facilities,
and an export pipeline connecting the gas fields
 
to the LNG facilities.
 
The LNG is being sold to Sinopec under
20-year sales agreements for 7.6 million metric tonnes
 
of LNG per year, and Japan-based Kansai Electric
Power Co., Inc. under a 20-year sales agreement for approximately
 
1 million metric tonnes of LNG per year.
 
 
As of December 31, 2019, APLNG has an outstanding
 
balance of $6.7 billion on a $8.5 billion
 
project finance
facility.
 
In late 2018 and early 2019, APLNG successfully
 
refinanced $4.6 billion of the project finance
facility through three separate transactions, which
 
added lower cost United States Private Placement (USPP)
bond and commercial bank facilities.
 
In conjunction with these transactions, APLNG
 
made voluntary
repayments of $2.2 billion to a syndicate of Australian
 
and international commercial banks and fully
extinguished $2.4 billion
 
of financing from the Export-Import Bank of
 
China.
 
Project finance interest
payments are bi-annual, concluding September 2030.
 
For additional information, see Note 3—Variable Interest Entities, Note 6—Investments, Loans and Long-
Term Receivables and Note 12—Guarantees, in the Notes to Consolidated Financial
 
Statements.
 
 
Bayu-Undan
The Bayu-Undan gas condensate field is located
 
in the Timor Sea Joint Petroleum Development Area between
Timor-Leste and Australia.
 
We also operate and own a 56.9 percent interest in the associated Darwin LNG
Facility, located at Wickham Point, Darwin.
 
The Bayu-Undan natural gas recycle facility processes wet
 
gas; separates, stores and offloads condensate,
propane and butane; and re-injects dry gas back into
 
the reservoir.
 
In addition, a 310-mile natural gas pipeline
connects the facility to the 3.5-million-metric-tonnes-per-year
 
capacity Darwin LNG Facility.
 
Produced
natural gas is piped to the
 
Darwin LNG Plant, where it is converted
 
into LNG before being transported to
international markets.
 
In 2019, we sold 133 billion gross cubic feet
 
of LNG primarily to utility customers in
Japan.
 
 
 
 
 
 
 
 
 
 
 
 
 
12
 
Athena/Perseus
The Athena production license (WA-17-L) in which we had a 50 percent working interest is located offshore
Western Australia and our entitlement to production ended in the fourth quarter of 2019.
 
Annualized average
production from this license was five MBOED in 2019.
 
 
 
Exploration
We
 
operate three exploration permits in the
 
Browse Basin, offshore northwest Australia, in
 
which we own a 40
percent interest in permits WA-315-P,
 
WA-398-P and TP 28, of the Greater
 
Poseidon Area.
 
Phase I of the
Browse Basin drilling campaign resulted in three discoveries
 
in the Greater Poseidon Area and Phase II
resulted in five additional discoveries.
 
All wells have been plugged and abandoned.
 
 
We
 
operate two retention leases in the Bonaparte
 
Basin, offshore northern Australia, where we
 
own a 37.5
percent interest in the Barossa and Caldita discoveries.
 
In April 2018, Barossa entered the FEED
 
phase of
development which continued through 2019.
 
During the FEED phase, costs and the technical
 
definition for the
project will be finalized, gas and condensate sales
 
agreements progressed, and access arrangements negotiated
with the owners of the Darwin LNG Facility
 
and Bayu-Darwin Pipeline.
 
In December 2019, we entered into an agreement
 
with 3D Oil to acquire a 75 percent interest
 
and operatorship
of an offshore Tasmanian Permit located in the Otway Basin.
 
The farm-in agreement is conditional upon the
agreement and signing of a JOA by both parties and required
 
government approvals.
 
We plan to conduct a 3D
seismic survey in the second half of 2020.
 
This activity is excluded from the dispositions
 
discussed below.
 
Dispositions
In the second quarter of 2019, we completed the sale
 
of our 30 percent interest in the Greater Sunrise
 
Fields to
the government of Timor-Leste.
 
In October 2019, we entered into an agreement
 
to sell the subsidiaries that hold our Australia-West assets and
operations to Santos with an expected completion date
 
in the first quarter of 2020, subject to regulatory
approvals and other specific conditions precedent.
 
These subsidiaries hold our 37.5 percent
 
interest in the
Barossa Project and Caldita Field, our 56.9 percent interest
 
in the Darwin LNG Facility and Bayu-Undan
Field, our 40 percent interest in the Greater Poseidon
 
Fields, and our 50 percent interest in the
 
Athena Field.
 
Production associated with the Australia-West assets to be sold was 48 MBOED in 2019.
 
 
For additional information on these transactions,
 
see
 
Note 5—Asset Acquisitions and Dispositions,
 
in the
Notes to Consolidated Financial Statements.
 
 
Indonesia
2019
Natural
Liquids
 
Gas
Total
Interest
Operator
MBD
MMCFD
MBOED
Average Daily Net Production
South Sumatra
54
%
ConocoPhillips
2
321
56
Total Indonesia
2
321
56
 
 
During 2019, we
 
operated three PSCs in Indonesia:
 
the Corridor Block and South Jambi
 
“B,”
 
both located in
South Sumatra, and Kualakurun in Central Kalimantan.
 
Currently, we have production from the Corridor
Block.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
13
 
South Sumatra
The Corridor PSC consists
 
of two oil fields and seven producing natural gas fields.
 
Natural gas is supplied
from the Grissik and Suban gas processing plants to the
 
Duri steamflood in central Sumatra and to
 
markets in
Singapore, Batam and West Java.
 
In 2019, we were awarded a 20-year
 
extension, with new terms, of the
Corridor PSC.
 
Under these terms, we retain a majority
 
interest and continue as operator for at least three
 
years
after 2023 and retain a participating interest until
 
2043.
 
Production from the South Jambi “B” PSC has reached depletion
 
and field development has been suspended.
 
This PSC expired on January 26, 2020 and has been
 
returned to the Government of Indonesia.
 
 
Exploration
 
We
 
hold a 60 percent working interest in
 
the Kualakurun PSC.
 
After completion of prospect evaluation, we
and the other joint venture partners decided to relinquish
 
all of the remaining acreage to the Government of
Indonesia.
 
 
Transportation
We
 
are a 35 percent owner of a consortium company that
 
has a 40 percent ownership in PT Transportasi Gas
Indonesia, which owns and operates the Grissik
 
to Duri and Grissik to Singapore natural gas pipelines.
 
China
2019
Natural
Liquids
Gas
Total
Interest
Operator
MBD
MMCFD
MBOED
Average Daily Net Production
Penglai
49.0
%
CNOOC
29
-
29
Panyu
24.5
CNOOC
6
-
6
Total China
35
-
35
 
 
Penglai
The Pengl
 
ai 19-
 
3, 19-9
 
and 25
 
-6
 
fields are
 
located in
 
Bohai Bay
 
Block 11/05
 
and are
 
in various
 
stages of
development.
 
As part
 
of further
 
development of
 
the Penglai
 
19-9 Field,
 
the wellhead
 
platform J
 
Project achieved
 
first
production in 2016.
 
This project will
 
include 62 wells,
 
57 of which have
 
been completed and brought
 
online
through December 2019.
 
 
The Penglai
 
19-3/19-9 Phase
 
3 Project
 
consists of
 
three new
 
wellhead platforms
 
and a
 
central processing
platform.
 
First oil from Phase 3 was achieved in
 
2018 for two of the platforms, with the third platform
 
planned
to come online
 
in the second
 
quarter of 2020.
 
This project could
 
include up to
 
186 wells, 42
 
of which have
been completed and brought online through December 2019.
 
 
In December 2018, we sanctioned the Penglai 25-6 Phase
 
4A Project.
 
This project consists of one new
wellhead platform and anticipates 62 new wells.
 
First production is expected in 2021.
 
 
Panyu
Our production license for Panyu
 
4-2, 5-1 and 11-6 located in Block 15/34 in the South China Sea
 
expired in
September 2019.
 
Annualized average production from these licenses
 
were six MBOED in 2019.
 
We
 
still have a license for Panyu 4-1 in Block
 
15/34 and are evaluating this area for potential
 
development.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
14
 
Exploration
Exploration activities in the Bohai Penglai Field during
 
2019 consisted of two successful appraisal wells,
 
a
full-field 3-D seismic program covering existing and
 
future development opportunities, and an
 
infill
compressive seismic imaging (CSI) survey to improve
 
imaging beneath the gas cloud in support of future
development projects.
 
In Block 15/34, one exploration well
 
was drilled in the Panyu 4-1E prospect and was
expensed as a dry hole.
 
Malaysia
2019
Natural
Liquids
Gas
Total
Interest
Operator
MBD
MMCFD
MBOED
Average Daily Net Production
Gumusut
29.0
%
Shell
23
-
23
Kebabangan (KBB)
30.0
KPOC
3
91
18
Malikai
35.0
Shell
15
-
15
Siakap North-Petai
21.0
PTTEP
1
-
1
Total Malaysia
42
91
57
 
We
 
have varying stages of exploration, development
 
and production activities across 2.2 million net acres
 
in
Malaysia, with working interests in six PSCs.
 
Three of these PSCs
 
are located off the eastern Malaysian state
of Sabah: Block G, Block J and the Kebabangan Cluster
 
(KBBC).
 
We operated three exploration blocks,
Block SK304, Block SK313 and Block WL4-00,
 
off the eastern Malaysian state of Sarawak.
 
Block J
Gumusut
First production from the Gumusut Field occurred from
 
an early production system in 2012.
 
Production from
a permanent, semi-submersible Floating Production System
 
was achieved in 2014.
 
We currently have a 29
percent working interest in the Gumusut Field
 
following the redetermination of the Block J and Block K
Malaysia Unit in 2017.
 
Gumusut Phase 2 first oil was achieved in 2019.
 
 
KBBC
The KBBC PSC grants us a 30 percent working interest
 
in the KBB, Kamunsu East and Kamunsu East
Upthrown Canyon gas and condensate fields.
 
 
KBB
First production from the KBB gas field was achieved in
 
2014.
 
During 2019, KBB tied-in to a nearby third-
party floating LNG vessel which provided increased
 
gas offtake capacity.
 
Production in 2020 is anticipated to
be impacted between 15 to 20 MBOED due to
 
the rupture of a third-party pipeline, in January
 
2020, which
carries gas production from the KBB gas field to market.
 
The extent of the required pipeline repairs, and the
amount of time required to return this pipeline to
 
full service is still being evaluated.
 
 
Kamunsu East
Development options for the Kamunsu East gas field are
 
being evaluated.
 
 
Block G
Malikai
We
 
hold a 35 percent working interest
 
in Malikai.
 
This field achieved first production in December
 
2016 via
the Malikai Tension Leg Platform, ramping to peak production in 2018.
 
The KMU-1 exploration well was
completed and started producing through the Malikai
 
platform in 2018.
 
Malikai Phase 2 development,
 
a 6-
well drilling campaign that will commence in 2020, reached
 
a final investment decision in late 2019.
 
 
15
 
Siakap North-Petai
We
 
hold a 21 percent working interest
 
in the unitized Siakap North-Petai oil field.
 
Exploration
In 2016, we entered into a farm-in agreement to acquire
 
a 50 percent working interest in Block SK 313,
 
a 1.4
million gross-acre exploration block offshore Sarawak, with
 
an effective date of January 2017.
 
Following
completion of the Sadok-1 exploration well in
 
January 2017, we assumed operatorship of
 
the block from
PETRONAS and completed a 3-D
 
seismic survey.
 
We
 
have no plans for further exploration
 
activity in this
block.
 
In 2017, we were awarded operatorship and a 50 percent
 
working interest in Block WL4-00, which included
the existing Salam-1 oil discovery and encompassed 0.6 million
 
gross acres.
 
In 2018 and 2019, two
exploration and two appraisal wells were drilled, resulting
 
in oil discoveries under evaluation at Salam and
Benum, while two Patawali wells were expensed
 
as dry holes in 2019.
 
 
In 2018, we were awarded a 50 percent working interest
 
and operatorship of Block SK304 encompassing
 
2.1
million gross acres offshore Sarawak.
 
We acquired 3-D seismic over the acreage and completed processing of
this data in 2019.
 
The Gemilang-1 exploration well in Block J was completed
 
in late 2018.
 
Development options are being
evaluated.
 
 
 
OTHER INTERNATIONAL
 
The Other International segment includes exploration
 
activities in Colombia, Chile and Argentina and
contingencies associated with prior operations.
 
Colombia
We
 
have an 80 percent operated interest in the
 
Middle Magdalena Basin Block VMM-3.
 
The block extends
over approximately 67,000 net acres and contains
 
the Picoplata-1
 
Well,
 
which completed drilling in 2015 and
testing in 2017.
 
Plug and abandonment activity started
 
during 2018 and completed in 2019.
 
In addition, we
have an 80 percent working interest in the VMM-2 Block
 
which extends over approximately 58,000 net acres
and is contiguous to the VMM-3 Block.
 
As part of a case brought forward by environmental groups,
 
the
Highest Administrative Court granted a preliminary
 
injunction temporarily suspending hydraulic
 
fracturing
activities until the substance of the case is decided.
 
As a result, ConocoPhillips filed two separate Force
Majeure requests before the competent authority for both blocks,
 
which were granted.
 
Chile
 
We
 
have a 49 percent interest in the Coiron
 
Block located in the Magallanes Basin in southern
 
Chile.
 
 
Argentina
In January 2019, we secured a 50 percent nonoperated
 
interest in the El Turbio Este Block, within the Austral
Basin in southern Argentina.
 
In 2019, we acquired and processed 3-D seismic
 
covering approximately 500
square miles, with evaluation of the data ongoing.
 
In November 2019, we acquired interests in two nonoperated
 
blocks in the Neuquén Basin targeting the Vaca
Muerta play.
 
We have a 50 percent interest in the Bandurria Norte Block and a 45 percent interest
 
in the
Aguada Federal Block.
 
In Bandurria Norte, one vertical and four horizontal wells
 
were tested and shut-in
during 2019.
 
In Aguada Federal, two horizontal wells were being
 
tested at the end of the year.
 
 
 
 
 
 
 
 
16
 
Venezuela and Ecuador
For discussion of our contingencies in Venezuela and Ecuador, see Note 13—Contingencies and
Commitments, in the Notes to Consolidated Financial
 
Statements.
 
 
OTHER
 
 
Marketing Activities
Our Commercial organization manages our worldwide commodity
 
portfolio, which mainly includes natural
gas, crude oil, bitumen, NGLs and LNG.
 
Marketing activities are performed through
 
offices in the U.S.,
Canada, Europe and Asia.
 
In marketing our production, we attempt to minimize
 
flow disruptions, maximize
realized prices and manage credit-risk exposure.
 
Commodity sales are generally made at
 
prevailing market
prices at the time of sale.
 
We
 
also purchase and sell third-party volumes to better position
 
the company to
satisfy customer demand while fully utilizing
 
transportation and storage capacity.
 
Natural Gas
Our natural gas production, along with third-party purchased
 
gas, is primarily marketed in the U.S., Canada,
Europe and Asia.
 
Our natural gas is sold to a diverse client
 
portfolio which includes local distribution
companies; gas and power utilities; large industrials;
 
independent, integrated or state-owned oil and gas
companies; as well as marketing companies.
 
To reduce our market exposure and credit risk, we also transport
natural gas via firm and interruptible transportation
 
agreements to major market hubs.
 
 
Crude Oil, Bitumen and Natural Gas Liquids
 
Our crude oil, bitumen and NGL revenues are derived
 
from production in the U.S., Canada, Australia,
 
Asia,
Africa and Europe.
 
These commodities are primarily sold
 
under contracts with prices based on market indices,
adjusted for location, quality and transportation.
 
 
LNG
LNG marketing efforts are focused on equity LNG production
 
facilities located in Australia and Qatar.
 
LNG
is primarily sold under long-term contracts with prices based
 
on market indices.
 
 
Energy Partnerships
Marine Well Containment Company (MWCC)
 
We
 
are a founding member of the MWCC, a non-profit
 
organization formed in 2010, which provides well
containment equipment and technology in the
 
deepwater U.S. Gulf of Mexico.
 
MWCC’s containment system
meets the U.S. Bureau of Safety and Environmental
 
Enforcement requirements for a subsea well
 
containment
system that can respond to a deepwater well control
 
incident in the U.S. Gulf of Mexico.
 
For additional
information, see Note 3—Variable Interest Entities, in the Notes to Consolidated Financial Statements.
 
 
 
Subsea Well Response Project (SWRP)
In 2011, we, along with several leading oil and gas companies,
 
launched the SWRP, a non-profit organization
based in Stavanger, Norway, which was created to enhance the industry’s capability to respond to international
subsea well control incidents.
 
Through collaboration with Oil Spill
 
Response Limited, a non-profit
organization in the U.K., subsea well intervention equipment
 
is available for the industry to use in the
 
event of
a subsea well incident.
 
This complements the work being
 
undertaken in the U.S.
 
by MWCC and provides well
capping and containment capability outside the U.S.
 
Oil Spill Response Removal Organizations (OSROs)
We
 
maintain memberships in several
 
OSROs across the globe as a key element of our preparedness
 
program in
addition to internal response resources.
 
Many of the OSROs are not-for-profit cooperatives owned
 
by the
member companies wherein we may actively participate
 
as a member of the board of directors, steering
committee, work group or other supporting role.
 
Globally, our primary OSRO is Oil Spill Response Ltd.
based in the U.K., with facilities in several other countries
 
and the ability to respond anywhere in the world.
 
In
North America, our primary OSROs include the Marine
 
Spill Response Corporation for the continental United
17
 
States and Alaska Clean Seas and Ship Escort/Response
 
Vessel
 
System for the Alaska North Slope and Prince
William Sound, respectively.
 
Internationally, we maintain memberships in various regional OSROs including
the Norwegian Clean Seas Association for Operating Companies,
 
Australian Marine Oil Spill Center and
Petroleum Industry of Malaysia Mutual Aid Group.
 
 
Technology
We
 
have several technology programs that improve
 
our ability to develop unconventional
 
reservoirs, produce
heavy oil economically with less emissions, improve
 
the efficiency of our exploration program, increase
recoveries from our legacy fields, and implement sustainability
 
measures.
 
Our Optimized Cascade
®
 
LNG liquefaction technology business
 
continues to be successful with the demand
for new LNG plants.
 
The technology has been licensed for use in 26
 
LNG trains around the world, with
feasibility studies ongoing for additional trains.
 
 
RESERVES
 
We
 
have not filed any information with
 
any other federal authority or agency with respect
 
to our estimated
total proved reserves at December 31, 2019.
 
No difference exists between our estimated total proved
 
reserves
for year-end 2018 and year-end 2017, which are shown
 
in this filing, and estimates of these reserves
 
shown in
a filing with another federal agency in 2019.
 
 
DELIVERY COMMITMENTS
 
We
 
sell crude oil and natural gas from our
 
producing operations under a variety of
 
contractual arrangements,
some of which specify the delivery of a fixed and determinable
 
quantity.
 
Our commercial organization also
enters into natural gas sales contracts where the source
 
of the natural gas used to fulfill
 
the contract can be the
spot market or a combination of our reserves and the spot
 
market.
 
Worldwide, we are contractually committed
to deliver approximately 1.1 trillion cubic feet of natural
 
gas, including approximately 75 billion cubic feet
related to the noncontrolling interests of consolidated
 
subsidiaries, and 172 million barrels of crude oil
 
in the
future.
 
These contracts have various expiration dates
 
through the year 2030.
 
We expect to fulfill the majority
of these delivery commitments with proved developed
 
reserves.
 
In addition, we anticipate using PUDs and
spot market purchases to fulfill any remaining commitments.
 
See the disclosure on “Proved Undeveloped
Reserves” in the “Oil and Gas Operations” section
 
following the Notes to Consolidated Financial
 
Statements,
for information on the development of PUDs.
 
 
COMPETITION
 
We
 
compete with private, public and state-owned
 
companies in all facets of the E&P business.
 
Some of our
competitors are larger and have greater resources.
 
Each of our segments is highly competitive, with no single
competitor, or small group of competitors, dominating.
 
We
 
compete with numerous other companies in the
 
industry, including state-owned companies, to locate and
obtain new sources of supply and to produce oil, bitumen,
 
NGLs and natural gas in an efficient, cost-effective
manner.
 
Based on statistics published in the September
 
2, 2019, issue of the
Oil and Gas Journal
, we were the
third-largest U.S.-based oil and gas company in worldwide
 
natural gas and liquids production and worldwide
liquids reserves in 2018.
 
We deliver our production into the worldwide commodity markets.
 
Principal
methods of competing include geological, geophysical
 
and engineering research and technology; experience
and expertise; economic analysis in connection with
 
portfolio management; and safely operating
 
oil and gas
producing properties.
 
 
 
18
 
GENERAL
 
At the end of 2019, we held a total of 942 active patents
 
in 50 countries worldwide, including 371
 
active U.S.
patents.
 
During 2019, we received 64 patents in the U.S.
 
and 90 foreign patents.
 
Our products and processes
generated licensing revenues of $69 million related
 
to activity in 2019.
 
The overall profitability of any
business segment is not dependent on any single patent,
 
trademark, license, franchise or concession.
 
Health, Safety and Environment
 
Our HSE organization provides tools and support to our
 
business units and staff groups to help them ensure
world class HSE performance.
 
The framework through which we safely manage our
 
operations, the HSE
Management System Standard, emphasizes process
 
safety, risk management, emergency preparedness and
environmental performance, with an intense focus on process
 
and occupational safety.
 
In support of the goal
of zero incidents, HSE milestones and criteria are established
 
annually to drive strong safety and
environmental performance.
 
Progress toward these milestones and criteria
 
are measured and reported.
 
HSE
audits are conducted on business functions periodically, and improvement actions
 
are established and tracked
to completion.
 
We have designed processes relating to sustainable development in our economic,
environmental and social performance.
 
Our processes, related tools and requirements
 
focus on water,
biodiversity and climate change, as well as social
 
and stakeholder issues.
 
The environmental information contained in Management’s Discussion
 
and Analysis of Financial Condition
and Results of Operations on pages 50 through 55 under
 
the captions “Environmental” and “Climate
 
Change”
is incorporated herein by reference.
 
It includes information on expensed and
 
capitalized environmental costs
for 2019 and those expected for 2020 and 2021.
 
Website Access to SEC Reports
Our internet website address is
www.conocophillips.com
.
 
Information contained on our internet website is not
part of this report on Form 8-K.
 
Our Annual Reports on Form 10-K, Quarterly Reports
 
on Form 10-Q, Current Reports on Form 8-K
 
and any
amendments to these reports filed or furnished pursuant
 
to Section
 
13(a) or 15(d) of the Securities Exchange
Act of 1934 are available on our website, free of charge,
 
as soon as reasonably practicable after such
 
reports
are filed with, or furnished to, the SEC.
 
Alternatively, you may access these reports at the SEC’s website at
www.sec.gov
.
19
 
Item 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
 
Management’s
 
Discussion and Analysis is the company’s analysis of its financial performance and of
significant trends that may affect future performance.
 
It should be read in conjunction with the financial
statements and notes, and supplemental oil and gas
 
disclosures included elsewhere in this report.
 
It contains
forward-looking statements including, without limitation, statements
 
relating
 
to the company’s plans,
strategies, objectives, expectations and intentions
 
that are made pursuant to the “safe harbor” provisions of
the Private Securities Litigation Reform Act of 1995.
 
The words “anticipate,” “estimate,” “believe,”
“budget,” “continue,” “could,” “intend,” “may,” “plan,” “potential,” “predict,” “seek,” “should,”
 
“will,”
“would,” “expect,” “objective,” “projection,” “forecast,” “goal,” “guidance,” “outlook,”
 
“effort,” “target”
and similar expressions identify forward-looking statements.
 
The company does not undertake to update,
revise or correct any of the forward-looking information unless required to do so under the federal securities
laws.
 
Readers are cautioned that such forward-looking statements should be read in conjunction with the
company’s
 
disclosures under the heading: “CAUTIONARY STATEMENT FOR THE PURPOSES OF THE
‘SAFE HARBOR’ PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995,”
beginning on page 60.
 
 
The terms “earnings” and “loss” as used in Management’s Discussion and Analysis refer to net income (loss)
attributable to ConocoPhillips.
 
 
BUSINESS ENVIRONMENT AND EXECUTIVE
 
OVERVIEW
 
 
ConocoPhillips is an independent E&P company with
 
operations and activities in 17 countries.
 
Our diverse,
low cost of supply portfolio includes resource-rich unconventional
 
plays in North America; conventional
assets in North America, Europe, Asia and Australia;
 
LNG developments; oil sands in Canada; and
 
an
inventory of global conventional and unconventional exploration
 
prospects.
 
Headquartered in Houston, Texas,
at December 31, 2019, we employed approximately
 
10,400 people worldwide and had total assets
 
of $71
billion.
 
 
 
Overview
 
 
 
Global oil prices continued to be volatile in 2019.
 
Optimism about worldwide economic growth
 
during the
first quarter turned to pessimism in the second quarter
 
as trade disputes dampened growth forecasts.
 
At the
end of the second quarter, geopolitical tensions in the Middle East, threatening
 
the safe passage of supertankers
carrying crude oil through the Persian Gulf, revived
 
oil prices.
 
Worldwide economic growth concerns returned
in the third quarter to depress prices, only to be reversed
 
again by geopolitical tensions in the Middle East,
 
as
oilfield infrastructure in Saudi Arabia was attacked,
 
temporarily disrupting approximately
 
five percent of the
world’s oil supply.
 
Production was restored relatively quickly, and prices settled in the fourth
 
quarter.
 
Brent
crude averaged $64
 
per barrel in 2019, down nine percent from
 
the prior year.
 
Our business strategy
anticipates prices will remain volatile and is designed
 
to be resilient in lower price environments,
 
while
retaining upside during periods of higher prices.
 
Portfolio diversification and optimization,
 
a strong balance
sheet and disciplined capital investment have positioned
 
our company to navigate through volatile energy
cycles.
 
 
Our value proposition principles, namely, to focus on financial returns, maintain
 
a strong balance sheet, deliver
compelling returns of capital, and expand cash flow
 
through disciplined capital investments, are
 
being
executed in accordance with our priorities for allocating
 
cash flows from the business.
 
These priorities are:
invest capital to sustain
 
production and pay our existing dividend; grow
 
our existing dividend; maintain debt at
a level we believe is sufficient to maintain a strong investment
 
grade credit rating through price cycles; allocate
greater than 30 percent of our net cash provided by operating
 
activities to share repurchases and dividends;
and,
 
invest capital in a disciplined fashion to grow our
 
cash from operations.
 
We believe our commitment to
20
 
our value proposition, as evidenced by the results discussed
 
below, positions us for success in an environment
of price uncertainty and ongoing volatility.
 
 
In 2019, we successfully delivered on our priorities.
 
We achieved production growth of five percent on a total
BOE basis compared with the prior year, with higher value oil
 
volumes growing eight percent.
 
Cash provided
by operating activities of $11.1 billion exceeded capital expenditures
 
and investments of $6.6 billion.
 
After
repurchasing $3.5 billion of our common stock
 
and paying $1.5 billion of dividends to shareholders,
 
we ended
the year with cash, cash equivalents and restricted
 
cash totaling $5.4 billion and $3.0 billion of short-term
investments.
 
In October, we announced an increase to our quarterly
 
dividend of 38 percent to $0.42 per share
and announced planned 2020 share buybacks of $3 billion.
 
 
In February 2020, we announced 2020 operating
 
plan capital of $6.5 billion to $6.7 billion.
 
The plan includes
funding for ongoing development drilling programs, major
 
projects, exploration and appraisal activities, as
well as base maintenance.
 
Capital spend is expected to be
 
higher in the first quarter largely from winter
construction and exploration and appraisal drilling in
 
Alaska.
 
This guidance does not include capital for
acquisitions.
 
 
 
Key Operating and Financial Summary
 
 
Significant items during 2019 included the following:
 
 
●
 
Net cash provided by operating activities was $11.1
 
billion and exceeded capital expenditures and
investments of $6.6 billion.
 
●
 
Repurchased $3.5 billion of shares and paid $1.5 billion
 
in dividends, representing 45 percent of net
cash provided by operating activities.
●
 
Increased the quarterly dividend by 38 percent to $0.42
 
per share.
●
 
Achieved 100 percent total reserve replacement
 
and 117 percent organic replacement.
●
 
Underlying production, which excludes Libya and
 
the net volume impact from closed dispositions and
acquisitions of 51 MBOED in 2019 and 47 MBOED
 
in 2018, grew 5 percent.
●
 
Increased production from the Lower 48 Big 3 unconventionals—Eagle
 
Ford, Bakken and Permian
Unconventional—by 22 percent year-over-year.
●
 
Executed successful Alaska appraisal program; conducted
 
appraisal drilling and commissioned
infrastructure at Montney in Canada.
●
 
Completed Lower 48, Alaska and Argentina acquisitions;
 
awarded a 20-year extension of the
Indonesia Corridor Block PSC, with new terms.
●
 
Generated $3 billion in disposition proceeds; entered into
 
agreements to sell Australia-West assets for
$1.4 billion and Niobrara for $0.4 billion, both
 
subject to customary closing adjustments,
 
as well as
regulatory and other approvals.
●
 
Reduced asset retirement obligations and accrued environmental
 
costs by $2.3 billion, primarily due to
closed and pending dispositions.
 
●
 
Ended the year with cash, cash equivalents and
 
restricted cash totaling $5.4 billion and short-term
investments of $3.0 billion.
●
 
Recognized a $296 million after-tax impairment related
 
to the sale of our Niobrara interests in the
Lower 48 segment.
●
 
Discontinued exploration activities in the Central
 
Louisiana Austin Chalk trend and recognized
 
$197
million after-tax in leasehold impairment and dry
 
hole expenses.
 
 
Operationally, we remain focused on safely executing our operating plan and maintaining
 
capital and cost
discipline.
 
Production of 1,348 MBOED increased 5
 
percent or 65 MBOED in 2019 compared with 2018.
 
Production, excluding Libya, of 1,305 MBOED increased
 
5 percent or 63 MBOED.
 
Underlying production,
which excludes Libya and the net volume impact from closed
 
dispositions and acquisitions of 51 MBOED
 
in
2019 and 47 MBOED in 2018, is used to measure our ability
 
to grow production organically.
 
Our underlying
production grew 5 percent in 2019 to 1,254 MBOED from
 
1,195 MBOED in 2018.
 
 
 
 
 
21
 
On September 30, 2019, we completed the sale of two ConocoPhillips
 
U.K. subsidiaries to Chrysaor E&P
Limited for proceeds of $2.2 billion after interest
 
and customary adjustments.
 
In 2019, we recorded a $1.7
billion before-tax and $2.1 billion after-tax gain associated
 
with this transaction.
 
Together the subsidiaries
sold our indirectly held exploration and production assets
 
in the U.K.,
 
including $1.8 billion of ARO.
 
Annualized average production associated with the U.K. assets
 
sold was 50 MBOED in 2019.
 
Reserves
associated with the U.K. assets sold were 84 MMBOE
 
at the time of disposition.
 
Results of operations for the
U.K. are reported within our Europe,
 
Middle East and North Africa segment.
 
 
In the second quarter of 2019, we completed the sale of
 
our 30 percent interest in the Greater Sunrise
 
Fields to
the government of Timor-Leste for $350 million and recognized
 
an after-tax gain of $52 million.
 
No
production or reserve impacts were associated with
 
the sale.
 
The Greater Sunrise Fields were included in our
Asia Pacific segment.
 
 
In October 2019, we entered into an agreement to sell
 
the subsidiaries that hold our Australia-West assets and
operations to Santos for $1.39 billion, plus customary
 
adjustments, with an effective date of January 1, 2019.
 
In addition, we will receive a payment of $75 million upon
 
final investment
 
decision of the Barossa
development project.
 
These subsidiaries hold our 37.5 percent interest
 
in the Barossa Project and Caldita
Field, our 56.9 percent interest in the Darwin LNG Facility
 
and Bayu-Undan Field, our 40 percent interest in
the Greater Poseidon Fields, and our 50 percent interest
 
in the Athena Field.
 
This transaction is expected to be
completed in the first quarter of 2020, subject to regulatory
 
approvals and the satisfaction of other specific
conditions precedent.
 
In 2019, production associated with the Australia-West assets to be sold was 48
MBOED.
 
Year-end 2019 reserves associated with these assets were 17 MMBOE.
 
We will retain our 37.5
percent interest in the Australia Pacific LNG project
 
and operatorship of that project’s LNG facility.
 
Results
of operations for the subsidiaries to be sold are reported
 
within our Asia Pacific segment.
 
 
In the fourth quarter of 2019, we signed an agreement
 
to sell our interests in the Niobrara shale play
 
for $380
million, plus customary adjustments,
 
and overriding royalty interests in certain future
 
wells.
 
We
 
recorded an
after-tax impairment of $296 million in the fourth quarter
 
of 2019 to reduce the carrying value to fair value.
 
In
2019, production from Niobrara was 11 MBOED.
 
Year-end 2019 reserves associated with the Niobrara assets
to be sold were 14 MMBOE.
 
This transaction is subject to regulatory approval
 
and other conditions precedent
and is expected to close in the first quarter of 2020.
 
The Niobrara results of operations are reported
 
within our
Lower 48 segment.
 
 
For more information regarding the accounting impacts of
 
these transactions, see Note 5—Asset Acquisitions
and Dispositions,
 
in the Notes to Consolidated Financial
 
Statements.
 
 
Business Environment
 
 
Brent crude oil prices averaged $64 per barrel in 2019,
 
ranging from a low of $53 per barrel in January
 
to a
high of almost $75 per barrel in April.
 
The energy industry has periodically experienced
 
this type of volatility
due to fluctuating supply-and-demand conditions and such
 
volatility may persist for the foreseeable future.
 
Commodity prices are the most significant factor impacting
 
our profitability and related reinvestment of
operating cash flows into our business.
 
Our strategy is to create value through price cycles by
 
delivering on
the foundational principles that underpin our value proposition;
 
focus on financial returns through cash flow
expansion, maintain balance sheet strength and deliver peer-leading
 
distributions.
 
Operational and Financial Factors Affecting Profitability
 
The focus areas we believe will drive our success through
 
the price cycles include:
 
 
●
 
Maintain a relentless focus on safety and environmental
 
stewardship.
 
Safety and environmental
stewardship, including the operating integrity of our
 
assets, remain our highest priorities, and we
 
are
committed to protecting the health and safety of
 
everyone who has a role in our operations and
 
the
communities in which we operate.
 
We
 
strive to conduct our business with
 
respect and care for both
the local and global environment and systematically
 
manage risk to drive sustainable business growth.
 
Demonstrating our commitment to sustainability
 
and environmental stewardship, on November
 
2017,
 
 
 
22
 
we announced our intention to target a 5 to 15 percent reduction
 
in our GHG emission
 
intensity by 2030.
 
In December 2018, we became a founding
 
member of the Climate Leadership
Council (CLC), an international policy institute founded
 
in collaboration with business and
environmental interests to develop a carbon dividend
 
plan.
 
Participation in the CLC provides another
opportunity for ongoing dialogue about carbon pricing
 
and framing the issues in alignment with our
public policy principles.
 
We also belong to and fund Americans For Carbon Dividends, the education
and advocacy branch of the CLC.
 
In early 2019, we issued our first
 
stand-alone Climate-related Risk
Report and incorporated this into our website during
 
our annual Sustainability Report update.
 
Our
sustainability efforts continued through 2019 with a focus on
 
advancing our action plans for climate
change, biodiversity, water and human rights.
 
We
 
are committed to building a learning organization
using human performance principles as we relentlessly
 
pursue improved HSE and operational
performance.
 
 
●
 
Focus on financial returns.
 
This is a core principle of our value proposition.
 
Our goal is to achieve
strong financial returns by exercising capital discipline,
 
controlling our costs, and continually
optimizing our portfolio.
 
 
o
 
Maintain capital allocation discipline.
 
We participate in a commodity price-driven and
capital-intensive industry, with varying lead times from when an investment decision
 
is made
to the time an asset is operational and generates cash
 
flow.
 
As a result, we must invest
significant capital dollars to explore for new oil and
 
gas fields, develop newly discovered
fields, maintain existing fields, and construct pipelines
 
and LNG facilities.
 
We
 
allocate
capital across a geographically diverse, low cost of
 
supply resource base, which combined
with legacy assets results in low production decline.
 
Cost of supply is the WTI equivalent
price that generates a 10 percent after-tax return on a point-forward
 
and fully burdened basis.
 
Fully burdened includes capital infrastructure, foreign
 
exchange, price related inflation and
G&A.
 
In setting our capital plans, we exercise a rigorous
 
approach that evaluates projects
using this cost of supply criteria, which should
 
lead to value maximization and cash flow
expansion using an optimized investment pace, not production
 
growth for growth’s sake.
 
Additional capital may be allocated toward growth,
 
but discipline will be maintained.
 
Our
cash allocation priorities call for the investment
 
of sufficient capital to sustain production and
pay the existing dividend.
 
 
In February 2020, we announced 2020 operating
 
plan capital of $6.5 billion to $6.7 billion.
 
The plan includes funding for ongoing development
 
drilling programs, major projects,
exploration and appraisal activities, as well as base maintenance.
 
Capital spend is expected to
be higher in the first quarter largely from winter construction
 
and exploration and appraisal
drilling in Alaska.
 
This guidance does not include capital for acquisitions.
 
 
o
 
Control costs and expenses.
 
Controlling operating and overhead
 
costs, without compromising
safety and environmental stewardship, is a high priority.
 
We
 
monitor these costs using
various methodologies that are reported to senior management
 
monthly, on both an absolute-
dollar basis and a per-unit basis.
 
Managing operating and overhead costs
 
is critical to
maintaining a competitive position in our industry, particularly in a low commodity
 
price
environment.
 
The ability to control our operating and overhead
 
costs impacts our ability to
deliver strong cash from operations.
 
In 2019, our production and operating expenses
 
were
two percent higher than 2018, primarily due to costs associated
 
with higher production
volumes, which grew five percent during the same
 
period.
 
 
 
 
 
 
23
 
o
 
Optimize our portfolio.
 
We continue to optimize our asset portfolio to focus on low cost of
supply assets that support our strategy.
 
In 2019, we continued to dispose of
 
or market certain
non-core assets, including the U.K.,
 
Australia-West and our Niobrara assets
 
in the Lower 48.
 
Additions to the portfolio were made in the Lower 48 with
 
bolt-on interests and acreage
acquisitions, in Alaska with the Nuna discovery acreage
 
acquisition, and internationally with
entrance into Argentina’s Neuquén and Austral Basins.
 
We
 
will continue to evaluate our
assets to determine whether they compete for capital
 
within our portfolio and will optimize
the portfolio as necessary, directing capital towards the most competitive
 
investments.
 
 
 
●
 
Maintain balance sheet strength.
 
We
 
believe balance sheet strength is critical in a cyclical
 
business
such as ours.
 
Our strong operating performance buffered by a solid balance sheet
 
enables us to deliver
on our priorities through the price cycles.
 
Our priorities include execution of our development plans,
maintaining a growing dividend,
 
and repurchasing shares on a dollar cost average basis.
 
 
●
 
Return value to shareholders.
 
We believe in delivering value to our shareholders via a growing,
sustainable dividend supplemented by share repurchases.
 
In 2019, we paid dividends on our common
stock of approximately $1.5 billion and repurchased
 
$3.5 billion of our common stock.
 
Combined,
our dividend and repurchases represented 45 percent of
 
our net cash provided by operating activities.
 
Since we initiated our current share repurchase program
 
in late 2016, we have repurchased $9.6
 
billion
of shares.
 
Additionally, as of December 31, 2019, $5.4 billion of repurchase authority remained
 
of the
$15 billion share repurchase program our Board of Directors
 
had authorized.
 
In February 2020, we
announced that the Board of Directors approved an increase
 
to our repurchase authorization from $15
billion to $25 billion, to support our plan for future share
 
repurchases.
 
Whether we undertake these
additional repurchases is ultimately subject to numerous
 
considerations, including market conditions
and other factors.
 
See Risk Factors beginning on page 21 in
 
our 2019 Annual Report on Form 10-K
“Our ability to declare and pay dividends and repurchase
 
shares is subject to certain considerations.”
 
 
In October 2019, we announced that our Board of Directors
 
approved an increase to our quarterly
dividend of 38 percent to $0.42 per share.
 
 
●
 
Add to our proved reserve base.
 
We primarily add to our proved reserve base in three ways:
 
o
 
Successful exploration, exploitation and development
 
of new and existing fields.
o
 
Application of new technologies and processes
 
to improve recovery from existing fields.
o
 
Purchases of increased interests in existing fields and bolt-on
 
acquisitions.
 
Proved reserve estimates require economic production
 
based on historical 12-month, first-of-month,
average prices and current costs.
 
Therefore, our proved reserves generally increase
 
as prices rise and
decrease as prices decline.
 
Reserve replacement represents the net change in
 
proved reserves, net of
production, divided by our current year production,
 
as shown in our supplemental reserve table
disclosures.
 
In 2019, our reserve replacement, which included
 
a net decrease of 0.1 billion BOE from
sales and purchases, was 100 percent.
 
Increased crude oil reserves accounted
 
for approximately 55
percent of the total change in reserves. Our organic reserve
 
replacement, which excludes the impact of
sales and purchases, was 117 percent in 2019.
 
Approximately 50 percent of organic reserve additions
were from Lower 48 unconventional assets.
 
The remaining additions were evenly distributed across
the other operating segments.
 
In the five years ended December 31, 2019, our reserve
 
replacement was negative 34 percent,
reflecting the impact of asset dispositions and lower
 
prices during that period.
 
Our organic reserve
replacement during the five years ended December
 
31, 2019, which excludes a decrease of 2.0 billion
BOE related to sales and purchases, was 40 percent,
 
reflecting development activities as
 
well as lower
prices during that period.
 
Historically, our reserve replacement has varied considerably year to year contingent
 
upon the timing
 
 
24
 
of major projects which may have long lead times between
 
capital investment and production.
 
In the
last several years, more of our capital has been
 
allocated to short cycle time, onshore, unconventional
plays.
 
Accordingly, we believe our recent success in replacing reserves can be viewed
 
on a trailing
three-year basis.
 
 
In the three years ended December 31, 2019, our reserve
 
replacement was 23 percent, reflecting the
impact of asset dispositions during that period.
 
Our organic reserve replacement during the three
years ended December 31, 2019, which excludes a
 
decrease of 1.8 billion BOE related to sales and
purchases, was 143 percent, reflecting reserve additions
 
from development activities.
 
Access to additional resources may become increasingly
 
difficult as commodity prices can make
projects uneconomic or unattractive.
 
In addition, prohibition of direct investment
 
in some nations,
national fiscal terms, political instability, competition from national oil companies, and
 
lack of access
to high-potential areas due to environmental or other
 
regulation may negatively impact our ability
 
to
increase our reserve base.
 
As such, the timing and level at which we add
 
to our reserve base may, or
may not, allow us to replace our production over
 
subsequent years.
 
 
●
 
Apply technical capability.
 
We leverage our knowledge and technology to create value and safely
deliver on our plans.
 
Technical strength is part of our heritage and allows us to economically
 
convert
additional resources to reserves, achieve greater operating
 
efficiencies and reduce our environmental
impact.
 
Companywide, we continue to evaluate
 
potential solutions to leverage knowledge of
technological successes across our operations.
 
 
 
We
 
have embraced the digital transformation
 
and are using digital innovations to work and
 
operate
more efficiently.
 
Predictive analytics have been adopted
 
in our operations and planning process.
 
Artificial intelligence, machine learning and deep
 
learning are being used for seismic advancements.
 
 
●
 
Attract, develop and retain a talented work force.
 
We strive to attract, develop and retain individuals
with the knowledge and skills to implement our business
 
strategy and who support our values and
ethics.
 
We
 
offer university internships across multiple disciplines
 
to attract the best early career
talent.
 
We
 
also recruit experienced hires to fill critical skills
 
and maintain a broad range of expertise
and experience.
 
We promote continued learning, development and technical training through
structured development programs designed to enhance
 
the technical and functional skills of our
employees.
 
 
 
 
 
 
D123119DP25I0.GIF
25
 
Other Factors Affecting Profitability
 
Other significant factors that can affect our profitability
 
include:
 
 
●
 
Energy commodity prices.
 
Our earnings and operating cash flows generally correlate
 
with industry
price levels for crude oil and natural gas.
 
Industry price levels are subject to factors
 
external to the
company and over which we have no control, including
 
but not limited to global economic health,
supply disruptions or fears thereof caused by civil
 
unrest or military conflicts, actions taken by
 
OPEC,
environmental laws, tax regulations, governmental policies
 
and weather-related disruptions.
 
The
following graph depicts the average benchmark prices
 
for WTI crude oil, Brent crude oil and U.S.
Henry Hub natural gas:
 
 
 
 
Brent crude oil prices averaged $64.30 per barrel
 
in 2019, a decrease of 9 percent compared with
$71.04 per barrel in 2018.
 
Similarly, WTI crude oil prices decreased 12 percent from $64.92 per
barrel in 2018 to $57.02 per barrel in 2019.
 
Crude oil prices weakened year over year
 
primarily due to
ample global supplies and a decelerating global economy.
 
Henry Hub natural gas price averages decreased 15
 
percent from $3.09 per MMBTU in 2018 to $2.63
per MMBTU in 2019.
 
Natural gas prices weakened in 2019
 
versus the prior year due to strong
production, while demand growth was dampened
 
by mild weather.
 
Our realized NGL prices decreased 34 percent from
 
$30.48 per barrel in 2018 to $20.09 per barrel in
2019.
 
NGL prices weakened year over year due
 
to strong supply growth with only moderate demand
growth.
 
Our realized bitumen price increased 42 percent
 
from $22.29 per barrel in 2018 to $31.72 per barrel in
2019.
 
Curtailment orders imposed by the Alberta Government,
 
which limited production from the
province starting January 2019, provided strength to the
 
WCS differential to WTI at Hardisty.
 
We
continue to optimize bitumen price realizations through
 
the utilization of downstream transportation
solutions and implementation of alternate blend
 
capability which results in lower diluent costs.
 
Our worldwide annual average realized price decreased
 
9 percent from $53.88
 
per BOE in 2018 to
$48.78
 
per BOE in 2019 due to lower realized
 
oil, natural gas and NGL prices.
 
 
North America’s energy supply landscape has been transformed from one of resource
 
scarcity to one
of abundance.
 
In recent years, the use of hydraulic fracturing
 
and horizontal drilling in
unconventional formations has led to increased industry
 
actual and forecasted crude oil and natural
 
 
 
26
 
gas production in the U.S.
 
Although providing significant short- and long-term
 
growth opportunities
for our company, the increased abundance of crude oil and natural gas due to development
 
of
unconventional plays could also have adverse financial
 
implications to us, including: an extended
period of low commodity prices; production curtailments;
 
and delay of plans to develop areas such as
unconventional fields.
 
Should one or more of these events occur, our revenues would be reduced,
 
and
additional asset impairments might be possible.
 
●
 
Impairments.
 
We
 
participate in a capital-intensive industry.
 
At times, our PP&E and investments
become impaired when, for example, commodity
 
prices decline significantly for long periods
 
of time,
our reserve estimates are revised downward, or a decision
 
to dispose of an asset leads to a write-down
to its fair value.
 
We may also invest large amounts of money in exploration which, if exploratory
drilling proves unsuccessful, could lead to a material
 
impairment of leasehold values.
 
As we optimize
our assets in the future, it is reasonably possible we
 
may incur future losses upon sale or
 
impairment
charges to long-lived assets used in operations, investments
 
in nonconsolidated entities accounted for
under the equity method, and unproved properties.
 
A sustained decline in the current and long-term
outlook on gas price could affect the carrying value of certain
 
Lower 48 non-core gas assets and it is
reasonably possible this could result in a future non-cash impairment.
 
For additional information on
our impairments in 2019, 2018 and 2017, see Note 9—Impairments,
 
in the Notes to Consolidated
Financial Statements.
 
●
 
Effective tax rate.
 
Our operations are in countries with different
 
tax rates and fiscal structures.
 
Accordingly, even in a stable commodity price and fiscal/regulatory environment, our
 
overall
effective tax rate can vary significantly between periods based
 
on the “mix” of before-tax earnings
within our global operations.
 
 
●
 
Fiscal and regulatory environment.
 
Our operations can be affected by changing economic,
 
regulatory
and political environments in the various countries in
 
which we operate, including the U.S.
 
Civil
unrest or strained relationships with governments may
 
impact our operations or investments.
 
These
changing environments could negatively impact
 
our results of operations, and further changes
 
to
increase government fiscal take could have a negative
 
impact on future operations.
 
Our management
carefully considers the fiscal and regulatory environment
 
when evaluating projects or determining the
levels and locations of our activity.
 
 
 
Outlook
 
Full-year 2020 production is expected to be 1,230 MBOED
 
to 1,270 MBOED, including the impact of a recent
third-party pipeline outage on the Kebabangan Field in Malaysia.
 
First-quarter 2020 production is expected to
be 1,240 MBOED to 1,280 MBOED.
 
Production guidance for 2020 excludes Libya.
 
Operating Segments
 
We
 
manage our operations through six operating
 
segments, which are primarily defined by geographic
 
region:
Alaska; Lower 48; Canada; Europe, Middle East and North
 
Africa; Asia Pacific and Other International.
 
Corporate and Other represents costs not directly
 
associated with an operating segment, such as
 
most interest
expense, premiums incurred on the early retirement
 
of debt, corporate overhead, certain technology
 
activities,
as well as licensing revenues.
 
 
Our key performance indicators, shown in the statistical
 
tables provided at the beginning of the operating
segment sections that follow, reflect results from our operations, including commodity prices
 
and production.
 
 
 
 
 
 
 
 
 
27
 
RESULTS OF OPERATIONS
Effective with the third quarter of 2020, we have restructured our segments to align with changes to our
internal organization.
 
The Middle East business was realigned from the Asia Pacific and Middle East segment
to the Europe and North Africa segment.
 
The segments have been renamed the Asia Pacific segment and the
Europe, Middle East and North Africa segment.
 
We have revised segment information disclosures and
segment performance metrics presented within our results of operations for the
 
current and prior years.
Consolidated Results
A summary of the company’s net income (loss) attributable to ConocoPhillips
 
by business segment follows:
Millions of Dollars
Years
 
Ended December 31
2019
2018
2017
Alaska
$
1,520
1,814
1,466
Lower 48
436
1,747
(2,371)
Canada
279
63
2,564
Europe, Middle East and North Africa
3,170
2,594
1,116
Asia Pacific
1,483
1,342
(1,661)
Other International
263
364
167
Corporate and Other
38
(1,667)
(2,136)
Net income (loss) attributable to ConocoPhillips
$
7,189
6,257
(855)
 
 
2019 vs. 2018
 
Net income attributable to ConocoPhillips increased $932
 
million in 2019.
 
The increase was mainly due to:
 
●
 
A $2.1 billion after-tax gain associated with the completion
 
of the sale of two ConocoPhillips U.K.
subsidiaries to Chrysaor E&P Limited.
 
●
 
An unrealized gain of $649 million after-tax on our Cenovus
 
Energy (CVE) common shares in 2019,
as compared to a $436 million after-tax unrealized loss
 
on those shares in 2018.
●
 
Higher crude oil sales volumes due to growth in the
 
Lower 48 unconventionals and from the
acquisition of incremental interests in operated assets
 
in Alaska during the second and fourth
 
quarters
of 2018.
 
●
 
The absence of premiums on early debt retirements
 
totaling $195 million after-tax.
●
 
A $164 million income tax benefit related to deepwater
 
incentive tax credits recognized for Malaysia
Block G.
●
 
A $151 million income tax benefit related to the revaluation
 
of deferred tax assets following
finalization of rules relating to the 2017 Tax Cuts and Jobs Act.
 
These increases in net income were partly offset by:
 
●
 
Lower realized crude oil, natural gas and NGL prices.
●
 
The absence of a $774 million after-tax gain on the
 
Clair disposition in the U.K.
●
 
A $296 million after-tax impairment related to the
 
sale of our Lower 48 Niobrara interests.
●
 
Lower equity in earnings of affiliates due to $120 million
 
of impairments to equity method
investments in our Lower 48 segment and a $118 million reduction in
 
equity earnings at QG3 in our
Europe, Middle East and North Africa segment due
 
to a deferred tax adjustment.
●
 
Higher exploration expenses, primarily in our Lower
 
48 segment due to $197
 
million after-tax of
leasehold impairment and dry hole costs associated
 
with our decision to discontinue exploration
activities in the Central Louisiana Austin Chalk
 
trend.
 
 
 
 
28
 
2018 vs. 2017
 
Net income attributable to ConocoPhillips increased $7,112
 
million
 
in 2018.
 
The increase was mainly due to:
 
●
 
Higher realized commodity prices on a more liquids-weighted
 
portfolio.
●
 
The absence of a combined $2.5 billion after-tax impairment
 
related to the sale of our interests in the
San Juan Basin and the marketing of our Barnett asset,
 
recognized in the second quarter of 2017.
●
 
The absence of a $2.4 billion before- and after-tax impairment
 
of our equity investment in Australia
Pacific LNG Pty Ltd (APLNG), recognized in the
 
second quarter of 2017.
●
 
Recognition of $774 million after-tax gain on the Clair disposition
 
in the United Kingdom, in the
fourth quarter of 2018.
●
 
Lower depreciation, depletion and amortization (DD&A)
 
expense, mainly due to lower unit-of-
production rates from reserve revisions and disposition
 
impacts.
●
 
Recognition of $417 million after-tax in other income
 
from a settlement agreement with PDVSA
 
in
2018.
 
●
 
Lower exploration expenses, primarily due to the
 
absence of first quarter 2017 charges in our Lower
48 and Other International segments.
●
 
Lower interest and debt expense because of a lower debt
 
balance.
●
 
Higher equity earnings in QG3 and APLNG, primarily
 
due to higher realized LNG prices, partly
 
offset
by the absence of volumes in 2018 related to the disposition
 
of our interest in the FCCL Partnership in
Canada in 2017.
 
 
These increases in net income were partly offset by:
 
●
 
The absence of $1.6 billion in after-tax gains related to the sale
 
of certain Canadian assets in 2017.
●
 
The absence of a $996 million deferred tax benefit
 
related to the disposition of certain Canadian
assets, recognized in the first quarter of 2017.
●
 
The absence of deferred tax benefits totaling $852
 
million related to the Tax Legislation enacted on
December 22, 2017.
●
 
An unrealized loss of $437 million on our Cenovus Energy
 
common shares in 2018.
 
●
 
The absence of a $337 million after-tax award, including interest,
 
from an arbitration settlement with
The Republic of Ecuador in 2017.
 
 
Income Statement Analysis
 
2019 vs. 2018
 
Sales and other operating revenues decreased 11 percent in 2019, mainly due to
 
lower realized crude oil,
natural gas and NGL prices, partly offset by higher sales volumes
 
of crude oil in the Lower 48 and Alaska.
 
Equity in earnings of affiliates decreased $295 million in 2019,
 
primarily due to impairments of equity method
investments in our Lower 48 segment totaling $155 million.
 
Additionally, equity earnings decreased $118
million resultant from a deferred tax adjustment at
 
QG3,
 
reported in our Europe, Middle East and North
 
Africa
segment.
 
For more information related to these
 
items, see Note 3—Variable Interest Entities and Note 5—
Asset Acquisitions and Dispositions, in the Notes
 
to Consolidated Financial Statements.
 
Gain on dispositions increased $903 million in 2019, primarily
 
due to a $1.7 billion
 
before-tax gain associated
with the completion of the sale of two ConocoPhillips
 
U.K. subsidiaries to Chrysaor E&P Limited.
 
Partly
offsetting this increase, was the absence of a $715 million
 
before-tax gain on the sale of a ConocoPhillips
subsidiary to BP in 2018, which held 16.5 percent of
 
our 24 percent interest in the BP-operated Clair
 
Field in
the U.K.
 
For additional information related to these dispositions,
 
see Note 5—Asset Acquisitions and
Dispositions, in the Notes to Consolidated Financial
 
Statements.
 
 
 
 
 
 
 
 
 
 
 
29
 
 
Other income increased $1,185 million in 2019, primarily
 
due to an unrealized gain of $649 million before-tax
on our CVE common shares in 2019, and the absence
 
of a $437 million before-tax unrealized loss on those
shares in 2018.
 
For discussion of our CVE shares, see
 
Note 7—Investment in Cenovus Energy, in the Notes to
Consolidated Financial Statements.
 
Purchased commodities decreased 17 percent in 2019, primarily
 
due to lower natural gas and crude oil prices.
 
Selling, general and administrative expenses increased $155
 
million in 2019, primarily due to higher costs
associated with compensation and benefits, including mark
 
to market impacts of certain key employee
compensation programs, and increased facility costs.
 
Exploration expenses increased $374 million in 2019,
 
primarily due to higher leasehold impairment
 
and dry
hole costs, mainly in our Lower 48 segment,
 
and higher exploration G&A expenses.
 
In 2019, we recorded a
$141 million before-tax leasehold impairment expense
 
due to our decision to discontinue exploration
 
activities
in the Central Louisiana Austin Chalk trend and expensed
 
$111 million of dry hole costs related to this play.
 
 
Impairments increased $378 million in 2019, mainly due
 
to a $379 million before-tax impairment related
 
to the
sale of our Niobrara interests in the Lower 48 segment.
 
For additional information, see Note 5—Asset
Acquisitions and Dispositions and Note 9—Impairments,
 
in the Notes to Consolidated Financial Statements.
 
 
Other expenses decreased $310 million in 2019, primarily
 
due to the absence of a $206 million before-tax
expense for premiums on early debt retirements and lower
 
pension settlement expense.
 
See Note 19—Income Taxes, in the Notes to Consolidated Financial Statements,
 
for information regarding our
income tax provision (benefit) and effective tax rate.
 
 
2018 vs. 2017
 
Sales and other operating revenues increased 25 percent
 
in 2018, due to higher realized commodity
 
prices,
mainly crude oil, on a portfolio with a higher mix
 
of crude oil and less of bitumen and natural gas.
 
Partly
offsetting this increase, were lower natural gas volumes sold
 
due to 2017 dispositions in the Lower 48 and
Canada.
 
 
Equity in earnings of affiliates increased $302 million
 
in 2018.
 
The increase in equity earnings was primarily
due to higher earnings from QG3 and APLNG
 
as a result of higher LNG prices for both affiliates and higher
oil prices in QG3.
 
Partly offsetting this increase, was the absence of equity
 
in earnings resulting from the
disposition of our investment in the FCCL Partnership
 
in 2017.
 
Gain on dispositions decreased $1,114 million in 2018.
 
The decrease was primarily due to the absence
 
of a
$2.1 billion before-tax gain on the sale of certain Canadian
 
assets recognized in 2017, partly offset by a $715
million before-tax gain recognized in the fourth quarter
 
of 2018 on the sale of a ConocoPhillips
 
subsidiary to
BP, which
 
held 16.5 percent of our 24 percent interest
 
in the BP-operated Clair Field in the United
 
Kingdom.
 
For additional information concerning gain on dispositions,
 
see Note 5—Asset Acquisitions and Dispositions,
in the Notes to Consolidated Financial Statements.
 
 
Other income decreased $356 million in 2018, mainly
 
due to a $437 million unrealized loss on our
 
Cenovus
Energy common shares in 2018 and the absence of a $337
 
million arbitration settlement, including interest,
with The Republic of Ecuador in 2017.
 
Partly offsetting the decrease, was $430 million
 
before-tax from a
settlement agreement with PDVSA in 2018.
 
 
 
 
 
 
 
 
 
 
30
 
For discussion of our Cenovus Energy shares, see Note 7—Investment
 
in Cenovus Energy, in the Notes to
Consolidated Financial Statements.
 
For discussion of our Ecuador and PDVSA settlements,
 
see Note 13—
Contingencies and Commitments, in the Notes
 
to Consolidated Financial Statements.
 
 
Purchased commodities increased 15 percent in 2018,
 
mainly due to higher crude oil volumes purchased
 
and
higher crude oil prices.
 
 
Production and operating expenses increased 1 percent
 
in 2018, primarily due to costs associated
 
with higher
underlying production volumes as well as higher maintenance
 
and wellwork, largely offset by the absence of
costs resulting from 2017 dispositions in our Canada
 
and Lower 48 segments.
 
 
Exploration expenses decreased $565 million in 2018, primarily
 
as a result of lower dry hole costs, leasehold
impairment expense and other exploration expenses.
 
 
Dry hole costs were reduced primarily due to the absence
 
of before-tax charges of $288 million for multiple
Shenandoah wells in the deepwater Gulf of Mexico,
 
including wells previously suspended.
 
These charges
were reflected in our Lower 48 segment during 2017.
 
 
Leasehold impairment expense was reduced mainly due
 
to the absence of before-tax charges of $51 million
 
for
Shenandoah and $38 million for certain Lower 48
 
mineral assets, both recognized in 2017.
 
 
Other exploration expenses were reduced mainly
 
due to the absence of a $43 million before-tax charge
 
for the
cancellation of our Athena drilling rig contract and
 
other rig stacking costs in our Other International
 
segment
in 2017.
 
For additional information on leasehold impairments
 
and other exploration expenses, see Note 8—Suspended
Wells and Other Exploration Expenses, and Note 9—Impairments, in the Notes to Consolidated
 
Financial
Statements.
 
 
DD&A decreased $889 million in 2018, mainly due to lower
 
unit-of-production rates from positive reserve
revisions and impacts from the 2017 dispositions in our
 
Canada and Lower 48 segments, partly
 
offset by
increased underlying production volumes.
 
Impairments decreased $6.6 billion in 2018, mainly due
 
to the absence of 2017 impairments of
 
$3.9 billion
before-tax related to our former interests in the San
 
Juan Basin and the Barnett, both in our Lower
 
48 segment,
as well as a $2.4 billion before-
 
and after-tax impairment of our equity investment
 
in APLNG.
 
For additional
information, see Note 6—Investments, Loans and Long-Term Receivables and Note 9—Impairments,
 
in the
Notes to Consolidated Financial Statements.
 
Taxes other than income taxes increased $239 million in 2018, primarily due to higher
 
production taxes in
Alaska and the Lower 48 corresponding with
 
higher realized commodity prices.
 
Interest and debt expense decreased $363 million
 
in 2018, primarily due to lower debt balances.
 
 
See Note 19—Income Taxes, in the Notes to Consolidated Financial Statements,
 
for information regarding our
income tax provision (benefit) and effective tax rate.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
31
 
Summary Operating Statistics
2019
2018
2017
Average Net Production
Crude oil (MBD)
Consolidated Operations
692
639
585
Equity affiliates
13
14
14
Total crude oil
705
653
599
Natural gas liquids (MBD)
Consolidated Operations
107
95
104
Equity affiliates
8
7
7
Total natural gas liquids
115
102
111
Bitumen (MBD)
Consolidated Operations
60
66
59
Equity affiliates
63
Total bitumen
60
66
122
Natural gas (MMCFD)
Consolidated Operations
1,753
1,743
2,263
Equity affiliates
1,052
1,031
1,007
Total natural gas
2,805
2,774
3,270
Total Production
 
(MBOED)
1,348
1,283
1,377
Dollars Per Unit
Average Sales Prices
 
Crude oil (per bbl)
Consolidated Operations
$
60.98
68.03
51.89
Equity affiliates
61.32
72.49
54.76
Total crude oil
60.99
68.13
51.96
Natural gas liquids (per bbl)
Consolidated Operations
18.73
29.03
24.21
Equity affiliates
36.70
45.69
38.74
Total natural gas liquids
20.09
30.48
25.22
Bitumen (per bbl)
Consolidated Operations
31.72
22.29
21.43
Equity affiliates
23.83
Total bitumen
31.72
22.29
22.66
Natural gas (per mcf)
Consolidated Operations
4.25
5.40
3.97
Equity affiliates
6.29
6.06
4.27
Total natural gas
5.03
5.65
4.07
Millions of Dollars
Worldwide Exploration Expenses
General and administrative; geological and geophysical,
lease rental, and other
$
322
274
368
Leasehold impairment
221
56
136
Dry holes
200
39
430
$
743
369
934
 
 
32
 
We
 
explore for, produce, transport and market crude oil, bitumen,
 
natural gas, LNG and NGLs on a worldwide
basis.
 
At December 31, 2019, our operations were producing
 
in the U.S., Norway, Canada, Australia, Timor-
Leste, Indonesia, China, Malaysia, Qatar and Libya.
 
2019 vs. 2018
 
Total production, including Libya, of 1,348 MBOED increased 65 MBOED or 5 percent
 
in 2019 compared
with 2018, primarily due to:
 
●
 
New wells online in the Lower 48.
●
 
An increased interest in the Western North Slope (WNS) and Greater Kuparuk Area (GKA)
 
of Alaska
following acquisitions closed in 2018.
 
●
 
Higher production in Norway due to drilling activity
 
and the startup of Aasta Hansteen in December
2018.
 
 
The increase in production during 2019 was partly offset by:
 
●
 
Normal field decline.
●
 
Disposition impacts from the U.K. and non-core
 
asset sales in the Lower 48.
 
Production excluding Libya was 1,305 MBOED in
 
2019 compared with 1,242 MBOED in 2018,
 
an increase of
63 MBOED or 5 percent.
 
Underlying production, which excludes Libya and
 
the net volume impact from
closed dispositions and acquisitions of 51 MBOED in
 
2019 and 47 MBOED in 2018, is used to measure
 
our
ability to grow production organically.
 
Our underlying production grew 5 percent to 1,254
 
MBOED in 2019
from 1,195 MBOED in 2018.
 
 
2018 vs. 2017
 
Total production, including Libya, of 1,283 MBOED decreased 7 percent in 2018 compared
 
with 2017,
primarily due to:
 
• Disposition impacts from asset sales in Canada and the Lower 48 in 2017.
• Normal field decline.
• Higher unplanned downtime, including a third-party pipeline outage in Malaysia
 
in 2018.
 
The decrease in production during 2018 was partly
 
offset by:
 
• New wells online, primarily from tight oil plays in the Lower 48 and Malikai
 
in Malaysia.
• Improved drilling and well performance in Alaska, Norway, Lower 48 and China.
• The continued rampup in Libya.
 
Production excluding Libya was 1,242 MBOED in
 
2018 compared with 1,356 MBOED in 2017.
 
The volume
from closed dispositions was approximately 200 MBOED
 
in 2017 and 15 MBOED in 2018.
 
The volume from
acquisitions was less than 10 MBOED in 2018.
 
Our underlying production, which excludes the full-year
impact of
 
acquisitions, dispositions, and Libya, increased
 
over 5 percent in 2018 compared with 2017.
 
 
 
 
 
 
 
 
 
 
 
 
 
33
 
Alaska
2019
2018
2017
Net Income Attributable to ConocoPhillips
 
(millions of dollars)
$
1,520
1,814
1,466
Average Net Production
Crude oil (MBD)
202
171
167
Natural gas liquids (MBD)
15
14
14
Natural gas (MMCFD)
7
6
7
Total Production
 
(MBOED)
218
186
182
Average Sales Prices
 
Crude oil (per bbl)
$
64.12
70.86
53.33
Natural gas (per mcf)
3.19
2.48
2.72
 
 
The Alaska segment primarily explores for, produces, transports and markets crude
 
oil, NGLs and natural gas.
 
In 2019, Alaska contributed 25 percent of our consolidated
 
liquids production and less than 1 percent of our
natural gas production.
 
2019 vs. 2018
 
Alaska reported earnings of $1,520 million in 2019,
 
compared with earnings of $1,814 million in 2018.
 
The
decrease in earnings was mainly due to lower realized
 
crude oil prices and higher production and operating and
DD&A expenses associated with incremental volumes from
 
acquisitions completed during 2018.
 
Additionally, earnings were lower due to the absence of a $98 million tax valuation
 
allowance reduction,
 
the
absence of a $79 million after-tax benefit resulting
 
from an accrual reduction due to a transportation
 
cost ruling
by the FERC,
 
and $62 million less in enhanced oil recovery
 
credits.
 
Partly offsetting these decreases in
earnings, were higher crude oil sales volumes due to
 
the GKA and WNS acquisitions completed
 
in 2018.
 
Average production increased 32 MBOED in 2019 compared with 2018, primarily
 
due to acquisitions at GKA
and WNS in 2018, which provided an incremental
 
38 MBOED of production in 2019, as well
 
as volumes from
new wells online.
 
These production increases were partly
 
offset by normal field decline.
 
Acquisition Update
In the third quarter of 2019, we completed the Nuna discovery
 
acreage acquisition for approximately $100
million, expanding the Kuparuk River Unit by 21,000 acres
 
and leveraging legacy infrastructure.
 
 
2018 vs. 2017
 
Alaska reported earnings of $1,814 million in 2018,
 
compared with earnings of $1,466 million in 2017.
 
The
increase in earnings was mainly due to higher realized crude
 
oil prices.
 
Additionally, earnings were improved
due to the absence of a $110 million after-tax impairment related to our
 
small interest in the Point Thomson
Unit, recognized in the first quarter of 2017; a $98 million
 
reduction in tax valuation allowance, recognized in
the fourth quarter of 2018; lower DD&A expense from
 
reserve additions; and a $79 million after-tax benefit
resulting from an accrual reduction due to a transportation
 
cost ruling by the Federal Energy Regulatory
Commission (FERC), recorded in the first quarter of
 
2018.
 
Partly offsetting these increases in earnings, was
the absence of an $892 million tax benefit from the revaluation
 
of allocated U.S. deferred taxes at a lower
federal statutory rate, in accordance with the Tax Legislation enacted in 2017.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
34
 
Consolidated production increased 2 percent in 2018
 
compared with 2017, primarily due to improved
 
drilling
and well performance, 8 MBOED from acquisitions
 
in the Western North Slope and the Greater Kuparuk
Area, and the startup of GMT-1 in the fourth quarter
 
of 2018, partly offset by normal field decline.
 
 
Acquisitions
During the second quarter of 2018, we obtained regulatory
 
approvals and completed a transaction with
Anadarko Petroleum Corporation to acquire its 22 percent
 
nonoperated interest in the Western North Slope of
Alaska, as well as its interest in the Alpine Transportation Pipeline,
 
for $386 million, after customary
adjustments.
 
In 2018, our Alaska segment net production
 
included 7 MBOED associated with the additional
interest acquired.
 
In addition, we now have 100 percent interest
 
in approximately 1.2 million
 
acres of
exploration and development lands, including the Willow Discovery.
 
In December of 2018, we completed a transaction with BP
 
to acquire their nonoperated interest in the Kuparuk
Assets in Alaska, and to sell a ConocoPhillips subsidiary
 
to BP, which held 16.5 percent of our 24 percent
interest in the BP-operated Clair Field in the United
 
Kingdom.
 
In 2018, our Alaska segment net production
included 1 MBOED related to the additional interest acquired
 
in the Greater Kuparuk Area.
 
See Note 5—
Asset Acquisitions and Dispositions in the Notes to
 
Consolidated Financial Statements, for additional
information.
 
Lower 48
2019
2018
2017
Net Income (Loss) Attributable to ConocoPhillips
 
(millions of dollars)
$
436
1,747
(2,371)
Average Net Production
Crude oil (MBD)
266
229
180
Natural gas liquids (MBD)
81
69
69
Natural gas (MMCFD)
622
596
898
Total Production
 
(MBOED)
451
397
399
Average Sales Prices
 
Crude oil (per bbl)
$
55.30
62.99
47.36
Natural gas liquids (per bbl)
16.83
27.30
22.20
Natural gas (per mcf)
2.12
2.82
2.73
 
 
The Lower 48 segment consists of operations located in the
 
contiguous U.S.
 
and the Gulf of Mexico.
 
During
2019, the Lower 48 contributed 41 percent of our consolidated
 
liquids production and 35 percent of our
 
natural
gas production.
 
 
2019 vs. 2018
 
Lower 48 reported earnings of $436 million
 
in 2019, compared with $1,747 million in 2018.
 
Earnings
decreased primarily due to lower realized crude oil,
 
NGL and natural gas prices; higher DD&A due
 
to
increased production volumes; a $301 million after-tax impairment
 
of our Niobrara assets; higher exploration
expenses, primarily due to a combined $197 million
 
after-tax of leasehold impairment and dry hole costs
associated with our decision to discontinue exploration
 
activities in the Central Louisiana Austin Chalk; and
lower earnings in equity affiliates due to a combined $120
 
million after-tax of impairments associated with a
fair value reduction of our investment in MWCC
 
and the disposition of our interests in the Golden
 
Pass LNG
Terminal and Golden Pass Pipeline.
 
Partly offsetting the decrease in earnings were
 
increased crude oil and
NGL sales volumes in the Eagle Ford, Bakken and Permian
 
Unconventional.
 
35
 
 
For additional information related to our impairment
 
of MWCC, see Note 3—Variable Interest Entities in the
Notes to Consolidated Financial Statements.
 
For more information related to the sale of
 
our interests in
Golden Pass LNG Terminal and Golden Pass Pipeline, see Note 5—Asset Acquisitions
 
and Dispositions in the
Notes to Consolidated Financial Statements.
 
 
Total average production increased 54 MBOED in 2019 compared with 2018.
 
The increase was primarily due
to new production from unconventional assets in Eagle
 
Ford, Bakken and the Permian Basin, partly
 
offset by
normal field decline.
 
Additionally, production decreased by 10
 
MBOED due to non-core dispositions
 
in 2018.
 
Asset Dispositions
 
Update
In January 2019, we entered into agreements to
 
sell our 12.4 percent ownership interests in
 
the Golden Pass
LNG Terminal and Golden Pass Pipeline.
 
We have also entered into agreements to amend our contractual
obligations for retaining use of the facilities.
 
As a result of entering into these agreements,
 
we recognized a
before-tax impairment of $60 million in the first quarter
 
of 2019 which is included in the “Equity in earnings
of affiliates” line on our consolidated income statement.
 
We
 
completed the sale in the second quarter of 2019.
 
See Note 15—Fair Value Measurement in the Notes to Consolidated Financial Statements, for additional
information.
 
In the fourth quarter of 2019, we sold our interests in
 
the Magnolia field and platform and
 
recognized an
 
after-
tax gain of $63 million.
 
Production from Magnolia in 2019
 
was less than one MBOED.
 
 
In the fourth quarter of 2019, we signed an agreement
 
to sell our interests in the Niobrara shale
 
play for $380
million, plus customary adjustments,
 
and overriding royalty interests in certain future
 
wells.
 
We
 
recorded an
after-tax impairment of $301 million in the fourth quarter
 
to reduce the carrying value to fair value.
 
Production from Niobrara was approximately 11 MBOED
 
in 2019.
 
This transaction is subject to regulatory
approval and other conditions precedent and is expected
 
to close in the first quarter of 2020.
 
 
In January 2020, we entered into an agreement
 
to sell our interests in certain non-core properties
 
in the Lower
48 segment for $186 million, plus customary adjustments.
 
The assets met the held for sale criteria in January
2020 and the transaction is expected to be completed in
 
the first quarter of 2020.
 
No gain or loss is anticipated
on the sale.
 
This disposition will not have a significant
 
impact on Lower 48 production.
 
 
For additional information on these transactions,
 
see Note 5—Asset Acquisitions and Dispositions,
 
in the
Notes to Consolidated Financial Statements.
 
 
2018 vs. 2017
 
Lower 48 reported earnings of $1,747 million
 
in 2018, compared with a net loss of $2,371
 
million in 2017.
 
Earnings increased primarily due to the absence of
 
a combined $2.5 billion after-tax impairment related to
 
the
sale of our interests in the San Juan Basin and the marketing
 
of our Barnett asset, recognized in the second
quarter of 2017; higher realized crude oil and NGL
 
prices; higher crude oil sales volumes;
 
lower DD&A
expense, primarily due to reserve additions and asset
 
disposition impacts, partly offset by higher underlying
volumes; lower exploration expenses and higher gain
 
on dispositions related to noncore asset
 
sales.
 
The
increase in earnings was partly offset by lower natural
 
gas sales volumes, primarily due to the disposition
 
of
our interests in the San Juan Basin in 2017.
 
 
In 2018, our average realized crude oil price of $62.99
 
per barrel was 3 percent less than WTI
 
of $64.92 per
barrel.
 
The differential was driven primarily by local market
 
dynamics in the Gulf Coast, Bakken and Permian
Basin.
 
Consolidated production decreased 1 percent in 2018
 
compared with 2017.
 
The decrease was mainly
attributable to normal field decline and disposition
 
impacts related to interests sold in the San
 
Juan Basin and
 
36
 
other noncore assets.
 
Adjusted for the impact of dispositions
 
of 82 MBOED in 2017, underlying production
increased approximately 25 percent in 2018 compared
 
with 2017, primarily due to new production from
unconventional assets in the Eagle Ford, Bakken and Permian
 
Basin.
 
Asset Dispositions
In the first quarter of 2018, we completed the sale
 
of certain properties in the Lower 48 segment
 
for net
proceeds of $112 million.
 
No gain or loss was recognized on the sale.
 
In the second quarter of 2018, we
completed the sale of a package of largely undeveloped acreage
 
for net proceeds of $105 million.
 
No gain or
loss was recognized on the sale.
 
In the third quarter of 2018, we completed
 
a noncash exchange of
undeveloped acreage in the Lower 48 segment.
 
This transaction was recorded at fair value resulting
 
in the
recognition of a $44 million after-tax gain.
 
In the fourth quarter of 2018, we sold
 
several packages of
undeveloped acreage in the Lower 48 segment for total
 
net proceeds of $162 million and recognized
 
gains of
approximately $140 million.
 
In the fourth quarter of 2018, we completed the sale of
 
our interests in the Barnett to Lime Rock Resources
 
for
$196 million after customary adjustments.
 
Production associated with the Barnett
 
averaged 8 MBOED in
2018, of which approximately 55 percent was natural gas
 
and 45 percent was natural gas liquids.
 
After-tax
impairment charges of $69 million were recognized during
 
2018.
 
On July 31, 2017, we completed the sale of our interests
 
in the San Juan Basin for total proceeds
 
comprised of
$2.5 billion in cash after customary adjustments
 
and a contingent payment of up to $300
 
million.
 
The six-year
contingent payment, effective beginning January 1, 2018, is
 
due annually for the periods in which the monthly
U.S. Henry Hub price is at or above $3.20 per million
 
British thermal units.
 
During 2018, we recorded gains
on dispositions for these contingent payments
 
of $28 million.
 
On September 29, 2017, we completed the sale of
 
our interest in the Panhandle assets for $178
 
million in cash
after customary adjustments.
 
See Note 5—Asset Acquisitions and Dispositions in the
 
Notes to Consolidated Financial Statements, for
additional information.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
37
 
Canada
2019
2018
2017
Net Income Attributable to ConocoPhillips
(millions of dollars)
$
279
63
2,564
Average Net Production
Crude oil (MBD)
1
1
3
Natural gas liquids (MBD)
-
1
9
Bitumen (MBD)
Consolidated operations
60
66
59
Equity affiliates
63
Total bitumen
60
66
122
Natural gas (MMCFD)
9
12
187
Total Production
 
(MBOED)
63
70
165
Average Sales Prices
 
Crude oil (per bbl)
$
40.87
48.73
43.69
Natural gas liquids (per bbl)
19.87
43.70
21.51
Bitumen (dollars per bbl)*
Consolidated operations
31.72
22.29
21.43
Equity affiliates
23.83
Total bitumen
31.72
22.29
22.66
Natural gas (per mcf)
0.49
1.00
1.93
*Average
 
prices for sales of bitumen produced
 
during 2018 and 2019 excludes additional
 
value realized from
 
the purchase and sale
 
of third-
party volumes for optimization
 
of our pipeline capacity between
 
Canada and the U.S. Gulf Coast.
 
Our Canadian operations consist of the Surmont oil
 
sands development in Alberta and the
 
liquids-rich
Montney unconventional play in British Columbia.
 
In 2019, Canada contributed 7 percent
 
of our consolidated
liquids production and less than one percent of our consolidated
 
natural gas production.
 
2019 vs. 2018
 
Canada operations reported earnings of $279 million
 
in 2019 compared with $63 million in 2018.
 
Earnings
increased mainly due to higher realized bitumen prices,
 
a $68 million tax benefit primarily comprised
 
of a
previously unrecognizable tax basis related to
 
a tax settlement, lower DD&A expense due to
 
lower rates from
reserve additions,
 
lower production and operating expenses,
 
and a $25 million tax benefit due to a four year
phased four percent reduction in Alberta’s corporate income tax rate.
 
Partly offsetting the increase in earnings
were lower sales volumes due to a planned turnaround
 
at Surmont,
 
lower production due to a mandated
production curtailment imposed by the Alberta government
 
in January 2019, and the absence of an $80 million
tax restructuring benefit.
 
Total average production decreased 7 MBOED in 2019 compared with 2018.
 
The production decrease was
primarily due to a turnaround at Surmont, which had an
 
annualized average impact of 3 MBOED, and a
mandated production curtailment imposed by the Alberta
 
government, which also impacted production by 3
MBOED.
 
The curtailment program is established and administered by
 
the Alberta Energy Regulator under the
Curtailment Rules regulation, which is currently set to
 
expire on December 31, 2020.
 
This program is
intended to strengthen the WCS differential to WTI at Hardisty.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
38
 
Asset Disposition
On May 17, 2017, we completed the sale of our 50 percent
 
nonoperated interest in the FCCL Partnership, as
well as the majority of our western Canada gas assets
 
to Cenovus Energy.
 
Consideration for the transaction
was $11.0 billion in cash after customary adjustments, 208 million
 
Cenovus Energy common shares and a five
year uncapped contingent payment.
 
The contingent payment, calculated and paid on a
 
quarterly basis, is $6
million CAD for every $1 CAD by which the WCS quarterly
 
average crude price exceeds $52 CAD per barrel.
 
During 2019 and 2018, we recorded after-tax gains on dispositions
 
for these contingent payments of $84
million and $68 million,
 
respectively.
 
See Note 5—Asset Acquisitions and Dispositions
 
in the Notes to
Consolidated Financial Statements, for additional information.
 
 
2018 vs. 2017
 
Canada operations reported earnings of $63 million
 
in 2018 compared with $2,564 million in 2017.
 
The
decrease was mainly due to the absence of a $1.6 billion
 
after-tax gain on the sale of our interest in the FCCL
Partnership and western Canada gas assets and an associated
 
$1.0 billion deferred tax benefit, and equity
earnings in the FCCL Partnership.
 
For additional information on the Canada
 
disposition, see Note 5—Asset
Acquisitions and Dispositions and Note 7—Investment
 
in Cenovus Energy, in the Notes to Consolidated
Financial Statements.
 
Total average production decreased 95 MBOED in 2018 compared with 2017.
 
The production decrease was
primarily due to our 2017 Canada disposition, partly
 
offset by strong well performance at Surmont.
 
Acquisition
In February 2018, we acquired approximately 34,500 net
 
acres of undeveloped land in the Montney for a net
purchase price of approximately $120 million.
 
The additional acreage is adjacent to our existing
 
position in
the liquids-rich portion of the Montney.
 
Europe, Middle East and North Africa
2019
*
2018
*
2017
*
Net Income Attributable to ConocoPhillips
 
(millions of dollars)
$
3,170
2,594
1,116
Consolidated Operations
Average Net Production
Crude oil (MBD)
138
149
142
Natural gas liquids (MBD)
7
8
8
Natural gas (MMCFD)
478
503
484
Total Production
 
(MBOED)
224
241
230
Average Sales Prices
 
Crude oil (dollars per bbl)
$
64.94
70.71
54.21
Natural gas liquids (per bbl)
29.37
36.87
34.07
Natural gas (per mcf)
4.92
7.65
5.70
*Prior periods have been
 
updated to reflect the Middle East
 
Business Unit moving
 
from Asia Pacific to the Europe,
 
Middle East and North
Africa segment.
 
See Note 25—Segment
 
Disclosures and
 
Related Information in the Notes to Consolidated
 
Financial Statements for additional
information.
 
 
The Europe,
 
Middle East and North Africa segment consisted
 
of operations principally located in the
Norwegian and U.K. sectors of the North Sea, the Norwegian
 
Sea, Qatar and Libya.
 
In 2019, our Europe,
 
 
39
 
Middle East and North Africa operations contributed 17
 
percent of our consolidated liquids production and
 
27
percent of our natural gas production.
 
2019 vs. 2018
 
Earnings for Europe, Middle East and North Africa operations
 
of $3,170 million increased $576 million in
2019 compared with 2018.
 
The increase
 
in earnings was primarily due to a $2.1 billion
 
after-tax gain
associated with the completion of the sale of two
 
ConocoPhillips U.K. subsidiaries to Chrysaor
 
E&P Limited.
 
Earnings also increased due to the cessation of DD&A in
 
the second quarter of 2019 for our disposed
 
U.K.
subsidiaries when these assets became held-for-sale.
 
Partly offsetting the increase in earnings were
 
the
absence of a $774 million after-tax gain related to the
 
sale of a ConocoPhillips subsidiary to BP, which held
16.5 percent of our 24 percent interest in the BP-operated
 
Clair Field in the U.K.; lower sales volumes
primarily due to the U.K. disposition to Chrysaor completed
 
September 30, 2019; lower earnings in equity
affiliates, primarily due to a deferred tax adjustment at QG3
 
that resulted in a $118 million reduction to equity
earnings; and lower realized natural gas and crude oil
 
prices.
 
Consolidated production decreased 7 percent in 2019,
 
compared with 2018.
 
The decrease was mainly due to
normal field decline and a 20 MBOED disposition impact
 
from the sale of our U.K. assets to Chrysaor
completed September 30, 2019.
 
Partly offsetting these production decreases were
 
volumes from new wells
online in Norway,
 
including the Aasta Hansteen Field which
 
achieved first production in December of
 
2018.
 
Asset Disposition Update
On September 30, 2019, we completed the sale of two ConocoPhillips
 
U.K. subsidiaries to Chrysaor E&P
Limited for proceeds of $2.2 billion after interest
 
and customary adjustments.
 
In 2019, we recorded a $1.7
billion before-tax and $2.1 billion after-tax gain associated
 
with this transaction.
 
Together the subsidiaries
sold indirectly held our exploration and production assets
 
in the U.K.,
 
including $1.8 billion of ARO.
 
Annualized average production associated with the U.K. assets
 
sold was 50 MBOED in 2019.
 
Reserves
associated with the U.K. assets sold were 84 MMBOE
 
at the time of disposition.
 
For additional information,
see Note 5—Asset Acquisitions and Dispositions in
 
the Notes to Consolidated Financial Statements.
 
 
2018 vs. 2017
 
Earnings for Europe, Middle East and North Africa operations
 
of $2,594 million increased $1,478 million in
2018 compared to 2017.
 
Earnings in 2018 included a $774
 
million after-tax gain related to the sale of a
ConocoPhillips subsidiary to BP, which held 16.5 percent of our 24 percent interest in the BP-operated Clair
Field in the United Kingdom.
 
Earnings were also improved due to higher
 
realized crude oil and natural gas
prices; increased equity earnings due to higher LNG
 
prices at QG3; and lower DD&A expense, primarily
 
due
to reserve additions.
 
Consolidated production increased 5 percent in 2018,
 
compared with 2017.
 
The increase was mainly due to
higher production in Libya and new wells online in
 
Norway and the United Kingdom.
 
These increases in
production were partly offset by normal field decline and the
 
final cessation of production in several producing
gas fields in the Southern North Sea in the third quarter
 
of 2018.
 
Production associated with the Southern
North Sea was 22 million cubic feet a day or 4 MBOED in
 
2018.
 
 
Disposition
In the fourth quarter of 2018, we completed a transaction
 
to sell a ConocoPhillips subsidiary to BP, which held
16.5 percent of our 24 percent interest in the BP-operated
 
Clair Field in the United Kingdom and acquire their
nonoperated interest in the Kuparuk Assets in Alaska.
 
In 2018, our Europe, Middle East and
 
North Africa
segment net production associated with the disposed
 
16.5 percent interest in the Clair Field was approximately
5 MBOED.
 
We recognized a $774 million after-tax gain in the fourth quarter related to this transaction, as
discussed above.
 
See Note 5—Asset Acquisitions and Dispositions
 
in the Notes to Consolidated Financial
Statements, for additional information.
 
 
 
 
 
 
 
 
 
 
 
 
40
 
 
Asia Pacific
2019
*
2018
*
2017
*
Net Income (Loss) Attributable to ConocoPhillips
(millions of dollars)
$
1,483
1,342
(1,661)
Consolidated Operations
Average Net Production
Crude oil (MBD)
85
89
93
Natural gas liquids (MBD)
4
3
4
Natural gas (MMCFD)
637
626
687
Total Production
 
(MBOED)
196
196
212
Average Sales Prices
 
Crude oil (dollars per bbl)
$
65.02
70.93
54.38
Natural gas liquids (dollars per bbl)
37.85
47.20
41.37
Natural gas (dollars per mcf)
5.91
6.15
4.98
*Prior periods have been
 
updated to reflect the Middle East
 
Business Unit moving
 
from Asia Pacific to the Europe,
 
Middle East and North
 
Africa
segment.
 
See Note 25—Segment
 
Disclosures and Related
 
Information in the Notes to Consolidated
 
Financial Statements for additional
information.
 
 
 
The Asia Pacific segment has operations in China, Indonesia,
 
Malaysia, Australia and Timor-Leste.
 
During
2019, Asia Pacific contributed 10 percent of our consolidated
 
liquids production and 36 percent of our natural
gas production.
 
 
2019 vs. 2018
 
Asia Pacific reported earnings of $1,483 million
 
in 2019, compared with $1,342 million in
 
2018.
 
The increase in
earnings was mainly due to a $164 million income
 
tax benefit related to deepwater incentive tax
 
credits from the
Malaysia Block G and a $52 million after-tax gain on disposition
 
of our interest in the Greater Sunrise Fields.
 
Partly offsetting this increase in earnings was lower realized
 
crude oil, NGL and natural gas prices and
 
lower
LNG and crude oil sales volumes.
 
Consolidated production was flat in 2019 compared
 
with 2018.
 
There were increases due to new production
from Malaysia, including first gas supply from KBB
 
to PFLNG1 in the second quarter of 2019 and
 
first oil from
Gumusut Phase 2 in the third quarter of 2019; and new wells
 
online in China, including Bohai Phase 3.
 
Offsetting these production increases
 
was normal field decline.
 
 
Asset Dispositions Update
In the second quarter of 2019, we recognized an after-tax
 
gain of $52 million upon completion of the sale of our
30 percent interest in the Greater Sunrise Fields to
 
the government of Timor-Leste for $350 million.
 
No
production or reserve impacts were associated with
 
the sale.
 
In October 2019, we entered into an agreement to sell
 
the subsidiaries that hold our Australia-West assets and
operations to Santos for $1.39 billion, plus customary
 
adjustments, with an effective date of January 1, 2019.
 
In
addition, we will receive a payment of $75 million
 
upon final investment decision of the Barossa development
project.
 
These subsidiaries hold our 37.5 percent interest
 
in the Barossa Project and Caldita Field, our 56.9
percent interest in the Darwin LNG Facility and Bayu-Undan
 
Field, our 40 percent interest in the Greater
Poseidon Fields, and our 50 percent interest in the Athena
 
Field.
 
This transaction is expected to be completed in
the first quarter of 2020, subject to regulatory approvals
 
and the satisfaction of other specific conditions
precedent.
 
In 2019, production associated with the Australia-West assets to be sold was
 
48 MBOED.
 
Year-end
 
 
 
41
 
2019 reserves associated with these assets were 17
 
MMBOE.
 
We
 
will retain our 37.5 percent interest in the
Australia Pacific LNG project and operatorship of that
 
project’s LNG facility.
 
 
See Note 5—Asset Acquisitions and Dispositions in the
 
Notes to Consolidated Financial Statements, for
additional information related to these dispositions.
 
 
2018 vs. 2017
 
Asia Pacific reported earnings of $1,342 million in 2018, compared
 
with a loss of $1,661 million in 2017.
 
The
increase in earnings was mainly due to the absence
 
of a $2,384 million before- and after-tax charge for
 
the
impairment of our APLNG investment in 2017, higher realized
 
commodity prices, and increased equity in
earnings of affiliates, mainly due to higher LNG prices at APLNG.
 
See the “APLNG” section of Note 6—
Investments, Loans and Long-Term Receivables, in the Notes to Consolidated Financial
 
Statements, for
information on the 2017 impairment of our APLNG
 
investment.
 
 
Consolidated production decreased 8 percent in 2018,
 
compared with 2017.
 
The decrease was primarily due to
unplanned downtime in Malaysia related to the rupture of
 
a third-party pipeline which carries gas production
from the Kebabangan gas field in Malaysia and normal
 
field decline.
 
This decrease was partly offset by new
wells online at Malakai in Malaysia and an infill
 
drilling program in China.
 
Other International
2019
2018
2017
Net Income Attributable to ConocoPhillips
(millions of dollars)
$
263
364
167
 
The Other International segment includes exploration
 
activities in Colombia, Chile and Argentina and
contingencies associated with prior operations.
 
2019 vs. 2018
 
Other International operations reported earnings of $263 million
 
in 2019, compared with earnings of $364
million in 2018.
 
The decrease in earnings was primarily due to the recognition
 
of $417 million after-tax in
other income related to a settlement agreement with
 
PDVSA in 2018, compared with $317 million after-tax
associated with this settlement agreement in 2019.
 
 
In 2018 and 2019, we
 
collected approximately $0.8 billion
 
of the $2.0 billion settlement with PDVSA.
 
PDVSA has defaulted on its remaining payment obligations
 
under this agreement, we are therefore now forced
to incur additional costs as we seek to recover any unpaid
 
amounts under the agreement.
 
For additional
information, see Note 13—Contingencies and Commitments
 
in the Notes to Consolidated Financial
Statements.
 
Argentina
In
 
January 2019, we secured a 50 percent nonoperated interest
 
in the El Turbio Este Block,
 
within the Austral
Basin in southern Argentina.
 
In 2019, we acquired and processed 3-D seismic
 
covering 500 square miles,
 
with
evaluation of the data ongoing.
 
In November 2019, we acquired interests in two nonoperated
 
blocks in the Neuquén Basin targeting the Vaca
Muerta play.
 
We have a 50 percent interest in the Bandurria Norte Block and a 45 percent interest
 
in the
Aguada Federal Block.
 
In Bandurria Norte, 1 vertical and 4 horizontal
 
wells
 
were tested and shut-in during
2019.
 
In Aguada Federal, 2 horizontal wells were being
 
tested at the end of the year.
 
 
 
 
 
 
 
 
 
 
 
42
 
2018 vs. 2017
 
Other International operations reported earnings of $364 million
 
in 2018, compared with earnings of $167
million in 2017.
 
The increase in earnings was primarily due
 
to recognizing $417 million after-tax in other
income under a settlement agreement with PDVSA
 
associated with an arbitration award issued by the
 
ICC.
 
Partly offsetting the increase in earnings, was the absence of
 
a $320 million after-tax award from an arbitration
settlement with The Republic of Ecuador in 2017.
 
See Note 13—Contingencies and Commitments
 
in the
Notes to Consolidated Financial Statements, for additional
 
information.
 
 
Corporate and Other
Millions of Dollars
2019
2018
2017
Net Income (Loss) Attributable to ConocoPhillips
Net interest
$
(604)
(680)
(739)
Corporate general and administrative expenses
(252)
(91)
(193)
Technology
123
109
20
Other
771
(1,005)
(1,224)
$
38
(1,667)
(2,136)
 
 
2019 vs. 2018
 
Net interest consists of interest and financing expense,
 
net of interest income and capitalized interest.
 
Net
interest decreased $76 million in 2019 compared with
 
2018,
 
primarily due to lower capitalized interest on
projects; increased interest income from holding higher
 
cash balances; and lower interest on debt expense
resultant from the retirement of $4.7
 
billion of debt in 2018; partly offset by the absence of an
 
accrual
reduction due to a transportation cost ruling by the FERC.
 
Corporate G&A expenses include compensation programs
 
and staff costs.
 
These costs increased by $161
million in 2019 compared with 2018, primarily due to
 
higher costs associated with compensation and
 
benefits,
including certain key employee compensation programs
 
and higher facility costs.
 
Technology includes our investment in new technologies or businesses, as well as licensing revenues.
 
Activities are focused on both conventional and tight oil
 
reservoirs, shale gas, heavy oil, oil sands,
 
enhanced
oil recovery and LNG.
 
Earnings from Technology increased by $14 million in 2019 compared with 2018,
primarily due to higher licensing revenues.
 
 
The category “Other” includes certain foreign currency transaction
 
gains and losses, environmental costs
associated with sites no longer in operation, other costs not
 
directly associated with an operating segment,
premiums incurred on the early retirement of debt,
 
unrealized holding gains or losses on equity securities,
 
and
pension settlement expense.
 
Earnings in “Other” increased by $1,776 million
 
in 2019 compared with 2018,
primarily due to an unrealized gain of $649 million
 
after-tax on our CVE common shares in 2019, and the
absence of a $436 million after-tax unrealized loss on those shares in
 
2018.
 
Additionally, earnings increased
due to the absence of $195 million in premiums on
 
the early retirement of debt, lower pension settlement
expense, and a $151 million tax benefit related to the
 
revaluation of deferred tax assets following
 
finalization
of rules related to the 2017 Tax Cuts and Jobs Act.
 
See Note 19—Income Taxes, in the Notes to Consolidated
Financial Statements, for additional information related
 
to the 2017 Tax Cuts and Jobs Act.
 
 
 
 
43
 
2018 vs. 2017
Net interest consists of interest and financing expense,
 
net of interest income and capitalized interest.
 
Net
interest decreased $59 million in 2018 compared with
 
2017, primarily due to less interest from lower
 
debt
balances, higher capitalized interest on projects, and
 
an accrual reduction due to a transportation
 
cost ruling by
the FERC in the first quarter of 2018.
 
Partly offsetting these impacts, were reduced tax
 
benefits on interest
expense following the Tax Legislation, which lowered the U.S. corporate income
 
tax rate from 35 percent to
21 percent effective January 1, 2018, and a lower tax benefit
 
due to higher interest from the fair market value
method of apportioning interest expense in the United
 
States.
 
Corporate general and administrative expenses include
 
compensation programs and staff costs.
 
These costs
decreased by $102 million in 2018 compared with
 
2017, primarily due to lower staff expenses and
 
costs
associated with certain key employee compensation
 
programs.
 
Technology includes our investment in new technologies or businesses, as well as licensing
 
revenues.
 
Activities are focused on tight oil reservoirs, LNG,
 
oil sands and other production operations.
 
Earnings from
Technology increased by $89 million in 2018 compared with 2017, primarily due to
 
higher licensing revenues.
 
 
The category “Other” includes certain foreign currency
 
transaction gains and losses, environmental
 
costs
associated with sites no longer in operation, other
 
costs not directly associated with an
 
operating segment,
premiums incurred on the early retirement of debt,
 
unrealized holding gains or losses on equity
 
securities, and
pension settlement expense.
 
Losses in “Other” decreased by $219 million
 
in 2018 compared with 2017,
primarily due to the absence of an $813 million tax
 
charge from the revaluation of deferred taxes at a lower
federal statutory rate, in accordance with the Tax Legislation enacted in 2017; lower
 
premiums on the early
retirement of debt; partly offset by a $437 million unrealized
 
loss on our Cenovus Energy common shares.
 
 
 
 
 
 
 
 
44
 
CAPITAL RESOURCES AND LIQUIDITY
Financial Indicators
Millions of Dollars
Except as Indicated
2019
2018
2017
Net cash provided by operating activities
$
11,104
12,934
7,077
Cash and cash equivalents
5,088
5,915
6,325
Short-term debt
105
112
2,575
Total debt
14,895
14,968
19,703
Total equity
35,050
32,064
30,801
Percent of total debt to capital*
30
%
32
39
Percent of floating-rate debt to total debt
5
%
5
5
*Capital includes total debt
 
and total equity.
 
To meet our short-
 
and long-term liquidity requirements, we look to a variety
 
of funding sources, including
cash generated from operating activities, proceeds from
 
asset sales, our commercial paper and credit facility
programs and our ability to sell securities using our
 
shelf registration statement.
 
In 2019, the primary uses of
our available cash were $6,636 million to support
 
our ongoing capital expenditures and investments
 
program;
$3,500 million to repurchase our common stock;
 
$2,910 million net purchases of investments, and
 
$1,500
million to pay dividends on our common stock.
 
During 2019, cash and cash equivalents decreased
 
by $827
million to $5,088 million.
 
We
 
believe current cash balances and cash generated
 
by operations, together with access to external
 
sources of
funds as described below in the “Significant Changes
 
in Capital” section, will be sufficient to meet
 
our funding
requirements in the near and long term, including our
 
capital spending program, share repurchases, dividend
payments and required debt payments.
 
Our commitment to disciplined execution of these
 
funding requirements includes cash
 
investment strategies
that position us for success in an environment of short-term
 
price volatility as well as extended downturns in
commodity prices.
 
The primary objectives of these cash investment
 
strategies in priority order are to protect
principal, maintain liquidity, and provide yield and total returns.
 
Funds for short-term needs to support
 
our
operating plan and provide resiliency to react to short-term
 
price volatility are invested in highly liquid
instruments with maturities within the year.
 
Funds we consider available to maintain resiliency
 
in longer term
price downturns and to capture opportunities outside
 
a given operating plan may be invested in instruments
with maturities greater than one year.
 
For additional information, see Note 1–Accounting
 
Policies and Note
14–Derivative and Financial Instruments.
 
 
 
Significant Changes in Capital
 
Operating Activities
During 2019, cash provided by operating activities was
 
$11,104 million, a 14 percent decrease from 2018.
 
The
decrease was primarily due to lower prices, lower collections
 
related to settlements reached with Ecuador and
PDVSA, and a pension contribution made in conjunction
 
with the sale of two U.K. subsidiaries, partially offset
by higher volumes.
 
 
While the stability of our cash flows from operating activities
 
benefits from geographic diversity, our short-
and long-term operating cash flows are highly dependent
 
upon prices for crude oil, bitumen, natural gas, LNG
and NGLs.
 
Prices and margins in our industry have historically
 
been volatile and are driven by market
conditions over which we have no control.
 
Absent other mitigating factors, as these prices
 
and margins
fluctuate, we would expect a corresponding change in
 
our operating cash flows.
 
 
45
 
The level of absolute production
 
volumes, as well as product and location mix, impacts
 
our cash flows.
 
Full-
year production averaged 1,348 MBOED in 2019.
 
Full-year production excluding Libya averaged
 
1,305
MBOED in 2019
 
and is expected to be 1,230 to 1,270 MBOED in 2020.
 
Future production is subject to
numerous uncertainties, including, among others, the volatile
 
crude oil and natural gas price environment,
which may impact investment decisions; the effects of price changes on
 
production sharing and variable-
royalty contracts; acquisition and disposition of fields;
 
field production decline rates; new technologies;
operating efficiencies; timing of startups and major turnarounds;
 
political instability; weather-related
disruptions; and the addition of proved reserves through
 
exploratory success and their timely and cost-effective
development.
 
While we actively manage these factors, production
 
levels can cause variability in cash flows,
although generally this variability has not been as
 
significant as that caused by commodity prices.
 
To maintain or grow our production volumes on an ongoing basis, we must continue to add
 
to our proved
reserve base.
 
Our proved reserves generally increase as prices rise
 
and decrease as prices decline.
 
In 2019,
our reserve replacement, which included a net decrease of
 
0.1 billion BOE from sales and purchases, was 100
percent.
 
Increased crude oil reserves accounted for
 
approximately 55 percent of the total change in reserves.
 
Our organic reserve replacement, which excludes the impact of
 
sales and purchases, was 117 percent in 2019.
 
Approximately 51 percent of organic reserve additions are
 
from Lower 48, 13 percent from Alaska, 12 percent
from Canada, 12 percent from Europe, Middle East and
 
North Africa and 12 percent from Asia Pacific.
 
 
In the five years ended December 31, 2019, our reserve
 
replacement, which included a decrease of
 
2.0 billion
BOE from sales and purchases, was negative 34 percent,
 
reflecting the impact of asset dispositions
 
and lower
prices during that period.
 
Our organic reserve replacement during the five years ended
 
December 31, 2019,
was 40 percent, reflecting development activities as well
 
as lower prices during that period.
 
 
Historically our reserve replacement has varied considerably
 
year to year contingent upon the timing of major
projects which may have long lead times between capital
 
investment and production.
 
In the last several years,
more of our capital has been allocated to short cycle time,
 
onshore, unconventional plays.
 
Accordingly, we
believe our recent success in replacing reserves can be
 
viewed on a trailing three-year basis.
 
 
In the three years ended December 31, 2019, our reserve
 
replacement was 23 percent, reflecting the impact
 
of
asset dispositions during that period.
 
Our organic reserve replacement during the three years
 
ended December
31, 2019, which excludes a decrease of 1.8 billion
 
BOE related to sales and purchases, was 143 percent,
reflecting reserve additions from development activities.
 
Reserve replacement represents the net change in proved reserves,
 
net of production, divided by our current
year production, as shown in our supplemental reserve table
 
disclosures. For additional information about our
2020 capital budget, see the “2020 Capital Budget” section
 
within “Capital Resources and Liquidity” and for
additional information on proved reserves, including both
 
developed and undeveloped reserves, see the “Oil
and Gas Operations” section of this report.
 
As discussed in the “Critical Accounting Estimates”
 
section, engineering estimates of proved reserves are
imprecise; therefore, each year reserves may be revised
 
upward or downward due
 
to the impact of changes in
commodity prices or as more technical data becomes available
 
on reservoirs.
 
We have reported revisions as
increases to reserves in the current period, however in prior
 
periods,
 
reported revisions as decreases to
reserves. It is not possible to reliably predict how revisions
 
will impact reserve quantities in the future.
 
 
Investing Activities
Proceeds from asset sales in 2019 were $3.0 billion.
 
We
 
completed the sale of two ConocoPhillips U.K.
subsidiaries to Chrysaor E&P Limited for $2.2 billion.
 
We
 
also completed the sale of several assets including
our 30 percent interest in the Greater Sunrise Fields for $350
 
million and received $106 million of contingent
payments from Cenovus Energy.
 
 
In the fourth quarter of 2019, we entered into an agreement
 
to sell the subsidiaries that hold our Australia-West
assets and operations to Santos for $1.39 billion, plus
 
customary adjustments.
 
In addition, we will receive a
 
46
 
payment of $75 million upon final investment decision
 
of the Barossa development project.
 
Also in the fourth
quarter of 2019, we signed an agreement to sell our interests
 
in the Niobrara shale play for $380 million, plus
customary adjustments,
 
and overriding royalty interests in certain future wells.
 
Both transactions are subject to
regulatory approval and other conditions precedent and expected
 
to close in the first quarter of 2020.
 
 
Investing activities in 2019 also included net purchases of
 
$2.9 billion of investments in short-term and long-
term
 
financial instruments. These investments
 
include time deposits, commercial paper as
 
well as debt
securities classified as available for sale.
 
The investment in short-term instruments was
 
$2.8 billion, the
remaining $0.1 billion was invested in long-term debt
 
securities.
 
For additional information, see Note 14–
Derivative and Financial Instruments.
 
Proceeds from asset sales in 2018 were $1.1 billion.
 
We completed several undeveloped acreage transactions
in our Lower 48 segment for a total of $267 million
 
after customary adjustments and another transaction in
 
our
Lower 48 segment for $112 million after customary adjustments.
 
We
 
completed the sale of our interests in the
Barnett to Lime Rock Resources for $196 million
 
after customary adjustments.
 
We also completed the sale of
a ConocoPhillips subsidiary to BP and received $253 million
 
net proceeds.
 
The subsidiary held 16.5 percent
of our 24 percent interest in the BP-operated Clair Field
 
in the U.K.
 
During 2018, we
 
received $95 million of
contingent payments from Cenovus Energy.
 
For additional information on our dispositions,
 
see Note 5—Asset Acquisitions and
 
Dispositions in the Notes
to Consolidated Financial Statements.
 
Commercial Paper and Credit Facilities
We
 
have a revolving credit facility totaling
 
$6.0 billion, expiring in May 2023.
 
Our revolving credit facility
may be used for direct bank borrowings, the issuance
 
of letters of credit totaling up to $500 million, or
 
as
support for our commercial paper program.
 
The revolving credit facility is broadly syndicated
 
among financial
institutions and does not contain any material
 
adverse change provisions or any covenants requiring
maintenance of specified financial ratios or credit
 
ratings.
 
The facility agreement contains a cross-default
provision relating to the failure to pay principal or
 
interest on other debt obligations of $200 million
 
or more
by ConocoPhillips, or any of its consolidated subsidiaries.
 
Credit facility borrowings may bear interest at a
 
margin above rates offered by certain designated banks in the
London interbank market or at a margin above the overnight
 
federal funds rate or prime rates offered by
certain designated banks in the U.S.
 
The agreement calls for commitment fees
 
on available, but unused,
amounts.
 
The agreement also contains early termination
 
rights if our current directors or their approved
successors cease to be a majority of the Board
 
of Directors.
 
The revolving credit facility supports the ConocoPhillips
 
Company $6.0 billion commercial paper program,
which is primarily a funding source for short-term working
 
capital needs.
 
Commercial paper maturities are
generally limited to 90 days.
 
We
 
had no commercial paper outstanding in programs
 
in place at December 31,
2019 or December 31, 2018.
 
We had no direct outstanding borrowings or letters of credit under the revolving
credit facility at
 
December 31, 2019 and December 31, 2018.
 
Since we had no commercial paper outstanding
and had issued no letters of credit, we had access
 
to $6.0 billion in borrowing capacity under our revolving
credit facility at December 31, 2019
.
 
 
Our current long-term debt ratings remained unchanged
 
in 2019 and are as follows:
 
Fitch - “A” with a “stable”
outlook; Moody’s Investors Services - “A3” with a “stable” outlook; and Standard
 
& Poor’s - “A” with a
stable outlook.
 
We do not have any ratings triggers on any of our corporate debt that would cause an
automatic default, and thereby impact our access to liquidity, in the event of
 
a downgrade of our credit rating.
 
If our credit rating were downgraded, it could increase
 
the cost of corporate debt available to us and restrict
 
our
access to the commercial paper markets.
 
If our credit rating were to deteriorate
 
to a level prohibiting us from
accessing the commercial paper market, we would still
 
be able to access funds under our revolving credit
facility.
 
 
 
47
 
Certain of our project-related contracts, commercial
 
contracts
 
and derivative instruments contain provisions
requiring us to post collateral.
 
Many of these contracts and instruments permit us to post
 
either cash or letters
of credit as collateral.
 
At December 31, 2019 and 2018, we had direct bank letters
 
of credit of $277 million
and $323 million, respectively, which secured performance obligations related to various
 
purchase
commitments incident to the ordinary conduct of business.
 
In the event of credit ratings downgrades, we may
be required to post additional letters of credit.
 
 
Shelf Registration
We
 
have a universal shelf registration statement
 
on file with the SEC under which we, as a
 
well-known
seasoned issuer, have the ability to issue and sell an indeterminate amount of
 
various types of debt and equity
securities.
 
 
 
Off-Balance Sheet Arrangements
 
As part of our normal ongoing business operations and
 
consistent with normal industry practice, we enter
 
into
numerous agreements with other parties to pursue
 
business opportunities, which share costs
 
and apportion
risks among the parties as governed by the agreements.
 
For information about guarantees, see Note 12—Guarantees,
 
in the Notes to Consolidated Financial
Statements, which is incorporated herein by reference.
 
 
Capital Requirements
 
For information about our capital expenditures
 
and investments, see the “Capital Expenditures”
 
section.
 
Our debt balance at December 31, 2019, was $14,895 million,
 
a decrease of $73 million from the balance at
December 31, 2018.
 
For more information on Debt, see Note
 
11—Debt, in the Notes to Consolidated
Financial Statements.
 
On January 30, 2019, we announced a quarterly dividend
 
of $0.305 per share.
 
The dividend was paid on
March 1, 2019, to stockholders of record at the close of
 
business on February 11, 2019.
 
On May 1, 2019, we
announced a quarterly dividend of $0.305 per share.
 
The dividend was paid on June 3, 2019, to stockholders
of record at the close of business on May 13, 2019.
 
On
 
July 11, 2019, we announced a quarterly dividend of
$0.305 per share.
 
The dividend was paid on September 3,
 
2019, to stockholders of record at the close of
business on July 22, 2019.
 
On October 7, 2019, we announced a 38 percent increase
 
in the quarterly dividend
to $0.42 per share.
 
The dividend was paid on December 2, 2019, to
 
stockholders of record at the close of
business on October 17, 2019.
 
In February 2020, we announced a quarterly
 
dividend of $0.42 per share,
payable March 2, 2020, to stockholders of record at the
 
close of business on February 14, 2020.
 
 
In late 2016, we initiated our current share repurchase program.
 
As of December 31, 2019, we had
 
announced
a total authorization to repurchase $15 billion of our
 
common stock.
 
We repurchased $3 billion in 2017, $3
billion in 2018 and $3.5 billion in 2019.
 
Of the remaining authorization, we expect to repurchase
 
$3 billion in
2020.
 
In February 2020, we announced that the Board
 
of Directors approved an increase to our
 
authorization
from $15 billion to $25 billion, to support our plan for future
 
share repurchases.
 
Whether we undertake these
additional repurchases is ultimately subject to numerous
 
considerations, market conditions and other factors.
 
See Risk Factors beginning on page 21 in our 2019
 
Annual Report on Form 10-K, “Our ability to
 
declare and
pay dividends and repurchase shares is subject to certain considerations.”
 
Since our share repurchase program
began in November 2016, we have repurchased 169 million
 
shares at a cost of $9.6 billion through December
31, 2019.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
48
 
Contractual Obligations
The table below summarizes our aggregate contractual
 
fixed and variable obligations as of December
 
31, 2019:
Millions of Dollars
Payments Due by Period
 
Up to 1
Years
Years
After
Total
 
Year
2–3
4–5
5 Years
Debt obligations (a)
$
14,175
18
1,018
605
12,534
Finance lease obligations (b)
720
87
157
141
335
Total debt
14,895
105
1,175
746
12,869
Interest on debt
11,339
856
1,671
1,603
7,209
Operating lease obligations (c)
1,050
379
377
145
149
Purchase obligations (d)
8,671
3,237
1,745
1,327
2,362
Other long-term liabilities
Pension and postretirement benefit
contributions (e)
1,375
440
540
395
-
Asset retirement obligations (f)
6,206
997
282
309
4,618
Accrued environmental costs (g)
171
28
33
21
89
Unrecognized tax benefits (h)
82
82
(h)
(h)
(h)
Total
$
43,789
6,124
5,823
4,546
27,296
 
 
(a)
 
Includes $204 million of net unamortized premiums,
 
discounts and debt issuance costs.
 
See Note 11—
Debt, in the Notes to Consolidated Financial Statements,
 
for additional information.
 
(b)
 
See Note 17—Non-Mineral Leases, in the Notes to
 
Consolidated Financial Statements, for
 
additional
information.
 
 
(c)
 
Includes $31 million of short-term leases that are not recorded
 
on our consolidated balance sheet.
 
See
Note 17—Non-Mineral Leases, in the Notes to Consolidated
 
Financial Statements, for additional
information.
 
 
(d)
 
Represents any agreement to purchase goods or
 
services that is enforceable and legally
 
binding and that
specifies all significant terms, presented on an undiscounted
 
basis.
 
Does not include purchase
commitments for jointly owned fields and facilities
 
where we are not the operator.
 
 
The majority of the purchase obligations are market-based
 
contracts related to our commodity business.
 
Product purchase commitments with third parties
 
totaled $2,426 million.
 
 
Purchase obligations of $5,111 million are related to agreements to access and utilize
 
the capacity of
third-party equipment and facilities, including pipelines
 
and LNG and product terminals, to transport,
process, treat and store commodities.
 
The remainder is primarily our net share of
 
purchase
commitments for materials and services for jointly
 
owned fields and facilities where we are the
 
operator.
 
 
(e)
 
Represents contributions to qualified and nonqualified
 
pension and postretirement benefit plans for
 
the
years 2020 through 2024.
 
For additional information related to expected benefit
 
payments subsequent to
2024, see Note 18—Employee Benefit Plans, in
 
the Notes to Consolidated Financial Statements.
 
(f)
 
Represents estimated discounted costs to retire and remove
 
long-lived assets at the end of their
operations.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
49
 
(g)
 
Represents estimated costs for accrued environmental
 
expenditures presented on a discounted
 
basis for
costs acquired in various business combinations
 
and an undiscounted basis for all other accrued
environmental costs.
 
(h)
 
Excludes unrecognized tax benefits of $1,095 million
 
because the ultimate disposition and timing
 
of any
payments to be made with regard to such amounts
 
are not reasonably estimable.
 
Although unrecognized
tax benefits are not a contractual obligation, they are
 
presented in this table because they represent
potential demands on our liquidity.
 
 
Capital Expenditures and Investments
Millions of Dollars
2019
2018
2017
Alaska
$
1,513
1,298
815
Lower 48
3,394
3,184
2,136
Canada
368
477
202
Europe, Middle East and North Africa
708
877
872
Asia Pacific
584
718
482
Other International
8
6
21
Corporate and Other
61
190
63
Capital Program
$
6,636
6,750
4,591
 
 
Our capital expenditures and investments for the
 
three-year period ended December 31, 2019, totaled $18.0
billion.
 
The 2019 expenditures supported key exploration
 
and developments, primarily:
 
 
●
 
Development, appraisal and exploration activities
 
in the Lower 48, including Eagle Ford,
 
Permian
Unconventional, and Bakken.
 
●
 
Appraisal and development activities in Alaska related
 
to the Western North Slope; development
activities in the Greater Kuparuk Area and the Greater Prudhoe
 
Area; leasehold acquisition in the
Greater Kuparuk Area.
 
●
 
Development activities across assets in Norway, as well as for assets in the
 
U.K. that recently have
been sold.
 
●
 
Optimization of oil sands development and appraisal
 
activities in liquids-rich plays in Canada.
 
●
 
Signature bonus for Indonesia Corridor Block production
 
sharing contract, as well as continued
development in China, Malaysia, Australia, and Indonesia.
 
 
 
2020 CAPITAL BUDGET
 
In February 2020, we announced 2020 operating
 
plan capital of $6.5 billion to $6.7 billion.
 
The plan includes
funding for ongoing development drilling programs, major
 
projects, exploration and appraisal activities, as
well as base maintenance.
 
Capital spend is expected to be higher in the
 
first quarter largely from winter
construction and exploration and appraisal drilling
 
in Alaska.
 
This guidance does not include capital for
acquisitions.
 
 
For information on PUDs and the associated costs to develop
 
these reserves, see the “Oil and Gas Operations”
section in this report.
 
 
50
 
Contingencies
A number of lawsuits involving a variety of claims
 
arising in the ordinary course of business have been
 
filed
against ConocoPhillips.
 
We also may be required to remove or mitigate the effects on the environment of
 
the
placement, storage, disposal or release of certain
 
chemical, mineral and petroleum substances
 
at various active
and inactive sites.
 
We
 
regularly assess the need for accounting
 
recognition or disclosure of these
contingencies.
 
In the case of all known contingencies (other
 
than those related to income taxes), we
 
accrue a
liability when the loss is probable and the amount is
 
reasonably estimable.
 
If a range of amounts can be
reasonably estimated and no amount within the range
 
is a better estimate than any other amount,
 
then the
minimum of the range is accrued.
 
We do not reduce these liabilities for potential insurance or third-party
recoveries.
 
If applicable, we accrue receivables for
 
probable insurance or other third-party
 
recoveries.
 
With
respect to income tax-related contingencies, we use a
 
cumulative probability-weighted loss accrual in cases
where sustaining a tax position is less than certain.
 
Based on currently available information, we
 
believe it is remote that future costs related to known
 
contingent
liability exposures will exceed current accruals by an
 
amount that would have a material adverse
 
impact on our
consolidated financial statements.
 
For information on other contingencies,
 
see “Critical Accounting
Estimates” and Note 13—Contingencies and Commitments,
 
in the Notes to Consolidated Financial Statements.
 
 
Legal and Tax Matters
We
 
are subject to various lawsuits and claims including
 
but not limited to matters involving oil and
 
gas royalty
and severance tax payments, gas measurement and valuation
 
methods, contract disputes, environmental
damages, climate change, personal injury, and property damage.
 
Our primary exposures for such matters
relate to alleged royalty and tax underpayments on
 
certain federal, state and privately owned
 
properties and
claims of alleged environmental contamination
 
from historic operations.
 
We
 
will continue to defend ourselves
vigorously in these matters.
 
Our legal organization applies its knowledge, experience and
 
professional judgment to the specific
characteristics of our cases, employing a litigation
 
management process to manage and monitor
 
the legal
proceedings against us.
 
Our process facilitates the early evaluation and quantification
 
of potential exposures in
individual cases.
 
This process also enables us to track those cases that
 
have been scheduled for trial and/or
mediation.
 
Based on professional judgment and experience
 
in using these litigation management
 
tools and
available information about current developments
 
in all our cases, our legal organization regularly assesses
 
the
adequacy of current accruals and determines if adjustment
 
of existing accruals, or establishment of new
accruals, is required.
 
See Note 19—Income Taxes, in the Notes to Consolidated Financial Statements,
 
for
additional information about income tax-related contingencies.
 
Environmental
We
 
are subject to the same numerous international,
 
federal, state and local environmental laws and regulations
as other companies in our industry.
 
The most significant of these environmental laws
 
and regulations include,
among others, the:
 
●
 
U.S. Federal Clean Air Act, which governs air
 
emissions.
●
 
U.S. Federal Clean Water Act, which governs discharges to water bodies.
●
 
European Union Regulation for Registration, Evaluation,
 
Authorization and Restriction of Chemicals
(REACH).
●
 
U.S. Federal Comprehensive Environmental Response,
 
Compensation and Liability Act (CERCLA
 
or
Superfund), which imposes liability on generators, transporters
 
and arrangers of hazardous substances
at sites where hazardous substance releases have
 
occurred or are threatening to occur.
●
 
U.S. Federal Resource Conservation and Recovery
 
Act (RCRA), which governs the treatment,
 
storage
and disposal of solid waste.
●
 
U.S. Federal Oil Pollution Act of 1990 (OPA90), under which owners and operators
 
of onshore
facilities and pipelines, lessees or permittees of an area
 
in which an offshore facility is located, and
owners and operators of vessels are liable for removal
 
costs and damages that result from a discharge
of oil into navigable waters of the U.S.
51
 
●
 
U.S. Federal Emergency Planning and Community Right-to-Know
 
Act (EPCRA), which requires
facilities to report toxic chemical inventories with
 
local emergency planning committees and response
departments.
●
 
U.S. Federal Safe Drinking Water Act, which governs the disposal of wastewater in
 
underground
injection wells.
●
 
U.S. Department of the Interior regulations, which relate
 
to offshore oil and gas operations in U.S.
waters and impose liability for the cost of pollution
 
cleanup resulting from operations, as well as
potential liability for pollution damages.
●
 
European Union Trading Directive resulting in European Emissions
 
Trading Scheme.
 
These laws and their implementing regulations set
 
limits on emissions and, in the case of discharges to water,
establish water quality limits and establish standards
 
and impose obligations for the remediation of releases
 
of
hazardous substances and hazardous wastes.
 
They also, in most cases, require permits
 
in association with new
or modified operations.
 
These permits can require an applicant to collect
 
substantial information in connection
with the application process, which can be expensive
 
and time consuming.
 
In addition, there can be delays
associated with notice and comment periods and the
 
agency’s processing of the application.
 
Many of the
delays associated with the permitting process are
 
beyond the control of the applicant.
 
Many states and foreign countries where we operate
 
also have, or are developing, similar environmental
 
laws
and regulations governing these same types of activities.
 
While similar, in some cases these regulations may
impose additional, or more stringent, requirements
 
that can add to the cost and difficulty of marketing or
transporting products across state and international
 
borders.
 
The ultimate financial impact arising from environmental
 
laws and regulations is neither clearly known nor
easily determinable as new standards, such as air emission
 
standards and water quality standards, continue
 
to
evolve.
 
However, environmental laws and regulations, including those
 
that may arise to address concerns
about global climate change, are expected to continue
 
to have an increasing impact on our operations
 
in the
U.S.
 
and in other countries in which we operate.
 
Notable areas of potential impacts include air emission
compliance and remediation obligations in the U.S.
 
and Canada.
 
An example is the use of hydraulic fracturing, an
 
essential completion technique that facilitates
 
production of
oil and natural gas otherwise trapped in lower
 
permeability rock formations.
 
A range of local, state, federal or
national laws and regulations currently govern hydraulic
 
fracturing operations, with hydraulic fracturing
currently prohibited in some jurisdictions.
 
Although hydraulic fracturing has been conducted
 
for many
decades, a number of new laws, regulations and permitting
 
requirements are under consideration by various
state environmental agencies, and others which could
 
result in increased costs, operating restrictions,
operational delays and/or limit the ability to
 
develop oil and natural gas resources.
 
Governmental restrictions
on hydraulic fracturing could impact the overall profitability
 
or viability of certain of our oil and natural gas
investments.
 
We have adopted operating principles that incorporate established industry standards designed
 
to
meet or exceed government requirements.
 
Our practices continually evolve as technology
 
improves and
regulations change.
 
 
We
 
also are subject to certain laws and regulations relating
 
to environmental remediation obligations
associated with current and past operations.
 
Such laws and regulations include CERCLA and RCRA
 
and their
state equivalents.
 
Longer-term expenditures are subject to
 
considerable uncertainty and may fluctuate
significantly.
 
We
 
occasionally receive requests for information
 
or notices of potential liability from the EPA and state
environmental agencies alleging we are a potentially
 
responsible party under CERCLA or an equivalent
 
state
statute.
 
On occasion, we also have been made
 
a party to cost recovery litigation by those agencies
 
or by
private parties.
 
These requests, notices and lawsuits
 
assert potential liability for remediation costs
 
at various
sites that typically are not owned by us, but allegedly
 
contain wastes attributable to our past operations.
 
As of
December 31, 2019, there were 15 sites around the
 
U.S.
 
in which we were identified as a potentially
responsible party under CERCLA and comparable
 
state laws.
52
 
 
For most Superfund sites, our potential liability
 
will be significantly less than the total site remediation
 
costs
because the percentage of waste attributable to us, versus
 
that attributable to all other potentially responsible
parties, is relatively low.
 
Although liability of those potentially
 
responsible is generally joint and several for
federal sites and frequently so for state sites, other
 
potentially responsible parties at sites where we are a
 
party
typically have had the financial strength to meet their
 
obligations, and where they have not, or
 
where
potentially responsible parties could not be located,
 
our share of liability has not increased materially.
 
Many of
the sites at which we are potentially responsible are
 
still under investigation by the EPA or the state agencies
concerned.
 
Prior to actual cleanup, those potentially
 
responsible normally assess site conditions,
 
apportion
responsibility and determine the appropriate remediation.
 
In some instances, we may have no liability or attain
a settlement of liability.
 
Actual cleanup costs generally occur after the parties
 
obtain EPA or equivalent state
agency approval.
 
There are relatively few sites where we are a major participant,
 
and given the timing and
amounts of anticipated expenditures, neither the
 
cost of remediation at those sites nor such costs
 
at all
CERCLA sites, in the aggregate, is expected to have
 
a material adverse effect on our competitive or financial
condition.
 
Expensed environmental costs were $511 million in 2019 and are
 
expected to be about $545 million per year
in 2020 and 2021.
 
Capitalized environmental costs were $194
 
million in 2019 and are expected to be about
$225 million per year in 2020 and 2021.
 
Accrued liabilities for remediation activities are not reduced
 
for potential recoveries from insurers or other
third parties and are not discounted (except those assumed
 
in a purchase business combination, which we do
record on a discounted basis).
 
Many of these liabilities result from CERCLA,
 
RCRA and similar state or international laws that
 
require us to
undertake certain investigative and remedial activities
 
at sites where we conduct, or once conducted,
operations or at sites where ConocoPhillips-generated waste
 
was disposed.
 
The accrual also includes a number
of sites we identified that may require environmental
 
remediation, but which are not currently the subject of
CERCLA, RCRA or other agency enforcement activities.
 
The laws that require or address environmental
remediation may apply retroactively and regardless of
 
fault, the legality of the original activities or the current
ownership or control of sites.
 
If applicable, we accrue receivables for probable
 
insurance or other third-party
recoveries.
 
In the future, we may incur significant
 
costs under both CERCLA and RCRA.
 
 
Remediation activities vary substantially in duration and
 
cost from site to site, depending on the mix of unique
site characteristics, evolving remediation technologies,
 
diverse regulatory agencies and enforcement policies,
and the presence or absence of potentially liable third
 
parties.
 
Therefore, it is difficult to develop reasonable
estimates of future site remediation costs.
 
At December 31, 2019, our balance sheet included
 
total accrued environmental costs of $171 million,
compared with $178 million at December 31, 2018, for
 
remediation activities in the U.S. and Canada.
 
We
expect to incur a substantial amount of these expenditures
 
within the next 30 years.
 
 
Notwithstanding any of the foregoing, and as with
 
other companies engaged in similar businesses,
environmental costs and liabilities are inherent
 
concerns in our operations and products, and there
 
can be no
assurance that material costs and liabilities will not be
 
incurred.
 
However, we currently do not expect any
material adverse effect upon our results of operations or financial
 
position as a result of compliance with
current environmental laws
 
and regulations.
 
 
53
 
Climate Change
Continuing political and social attention to the
 
issue of global climate change has resulted
 
in a broad range of
proposed or promulgated state, national and international
 
laws focusing on GHG reduction.
 
These proposed or
promulgated laws apply or could apply in countries
 
where we have interests or may have interests
 
in the future.
 
Laws in this field continue to evolve, and while it
 
is not possible to accurately estimate either
 
a timetable for
implementation or our future compliance costs relating
 
to implementation, such laws, if enacted, could
 
have a
material impact on our results of operations and financial
 
condition.
 
Examples of legislation or precursors for
possible regulation that do or could affect our operations
 
include:
 
●
 
European Emissions Trading Scheme (ETS), the program through
 
which many of the EU member
states are implementing the Kyoto Protocol.
 
Our cost of compliance with the EU
 
ETS in 2019 was
approximately $8 million before-tax.
●
 
The Alberta Carbon Competitiveness Incentive Regulation
 
(CCIR) requires any existing facility with
emissions equal to or greater than 100,000 metric tonnes
 
of carbon dioxide, or equivalent, per year to
meet an industry benchmark intensity.
 
The total cost of these regulations in 2019 was approximately
$4 million.
●
 
The U.S. Supreme Court decision in Massachusetts v. EPA, 549 U.S. 497, 127 S.Ct. 1438 (2007),
confirmed that the EPA has the authority to regulate carbon dioxide as an “air pollutant” under
 
the
Federal Clean Air Act.
●
 
The U.S. EPA’s
 
announcement on March 29, 2010 (published as
 
“Interpretation of Regulations that
Determine Pollutants Covered by Clean Air Act
 
Permitting Programs,” 75 Fed. Reg. 17004 (April
 
2,
2010)), and the EPA’s
 
and U.S. Department of Transportation’s joint promulgation of a Final Rule on
April 1, 2010, that triggers regulation of GHGs
 
under the Clean Air Act, may trigger more climate-
based claims for damages, and may result in longer agency
 
review time for development projects.
 
●
 
The U.S. EPA’s
 
announcement on January 14, 2015, outlining a series of
 
steps it plans to take to
address methane and smog-forming volatile organic compound
 
emissions from the oil and gas
industry.
 
The former U.S. administration established a
 
goal of reducing the 2012 levels in methane
emissions from the oil and gas industry by 40 to 45 percent
 
by 2025.
●
 
Carbon taxes in certain jurisdictions.
 
Our cost of compliance with Norwegian carbon
 
tax legislation
in 2019 was approximately $30 million (net share before-tax).
 
We also incur a carbon tax for
emissions from fossil fuel combustion in our British
 
Columbia and Alberta Operations totaling just
over $0.8
 
million (net share before-tax).
●
 
The agreement reached in Paris in December 2015
 
at the 21
st
 
Conference of the Parties to the United
Nations Framework on Climate Change, setting out a
 
new process for achieving global emission
reductions.
 
While the U.S.
 
announced its intention to withdraw from the Paris
 
Agreement, there is no
guarantee that the commitments made by the U.S.
 
will not be implemented, in whole or in part,
 
by
U.S. state and local governments or by major corporations
 
headquartered in the U.S.
 
In the U.S., some additional form of regulation
 
may be forthcoming in the future at the federal
 
and state levels
with respect to GHG emissions.
 
Such regulation could take any of several
 
forms that may result in the creation
of additional costs in the form of taxes, the restriction of
 
output, investments of capital to maintain compliance
with laws and regulations, or required acquisition
 
or trading of emission allowances.
 
We are working to
continuously improve operational and energy efficiency through
 
resource and energy conservation throughout
our operations.
 
Compliance with changes in laws and regulations
 
that create a GHG tax, emission trading scheme
 
or GHG
reduction policies could significantly increase our
 
costs, reduce demand for fossil energy derived products,
impact the cost and availability of capital and increase
 
our exposure to litigation.
 
Such laws and regulations
could also increase demand for less carbon intensive
 
energy sources, including natural gas.
 
The ultimate
impact on our financial performance, either positive or
 
negative, will depend on a number of factors,
 
including
but not limited to:
 
 
●
 
Whether and to what extent legislation or regulation
 
is enacted.
●
 
The timing of the introduction of such legislation
 
or regulation.
 
54
 
●
 
The nature of the legislation (such as a cap and trade system
 
or a tax on emissions) or regulation.
●
 
The price placed on GHG emissions (either by the
 
market or through a tax).
●
 
The GHG reductions required.
 
●
 
The price and availability of offsets.
●
 
The amount and allocation of allowances.
●
 
Technological and scientific developments leading to new products or services.
●
 
Any potential significant physical effects of climate change
 
(such as increased severe weather events,
changes in sea levels and changes in temperature).
 
●
 
Whether, and the extent to which, increased compliance costs are ultimately
 
reflected in the prices of
our products and services.
 
 
The company has responded by putting in place a
 
Sustainable Development Risk Management
 
Standard
covering the assessment and registering of significant
 
and high sustainable development risks based on their
consequence and likelihood of occurrence.
 
We have developed a company-wide Climate Change Action Plan
with the goal of tracking mitigation activities for
 
each climate-related risk included in the corporate
Sustainable Development Risk Register.
 
The risks addressed in our Climate Change Action
 
Plan fall into four broad categories:
 
●
 
GHG-related legislation and regulation.
●
 
GHG emissions management.
●
 
Physical climate-related impacts.
●
 
Climate-related disclosure and reporting.
 
Emissions are categorized into different scopes.
 
Scope 1 and Scope 2 GHG emissions help
 
us understand
climate transition risk.
 
Scope 1 emissions are direct GHG
 
emissions from sources that we own or control.
 
Scope 2 emissions are GHG emissions from the generation
 
of purchased electricity or steam that we consume.
 
Our corporate authorization process requires all
 
qualifying projects to run a GHG pricing
 
sensitivity using a
corporate price of $40 per tonne of carbon dioxide equivalent,
 
plus annual inflation, for all Scope 1 and Scope
2 GHG emissions produced in 2024 and later.
 
Projects in jurisdictions with existing GHG
 
pricing regimes
must incorporate that existing GHG price and its
 
forecast into their base case economics.
 
Where the existing
GHG price is below the corporate price, the $40 per
 
tonne of carbon dioxide equivalent sensitivity must
 
also be
run from 2024 onward.
 
Thus, both existing and emerging regulatory requirements
 
are considered in our
decision-making.
 
The company does not use an estimated
 
market cost of GHG emissions when assessing
reserves in jurisdictions without existing GHG
 
regulations.
 
In December 2018, we became a founding member
 
of the CLC, an international policy institute
 
founded in
collaboration with business and environmental interests
 
to develop a carbon dividend plan.
 
Participation in the
CLC provides another opportunity for ongoing dialogue
 
about carbon pricing and framing the issues in
alignment with our public policy principles.
 
We also belong to and fund Americans For Carbon Dividends,
the education and advocacy branch of the CLC.
 
 
In 2017 and 2018, cities, counties, and a state government
 
in California, New York, Washington,
 
Rhode Island
and Maryland, as well as the Pacific Coast Federation
 
of Fishermen’s Association, Inc., have filed lawsuits
against oil and gas companies, including ConocoPhillips,
 
seeking compensatory damages and equitable relief
to abate alleged climate change impacts.
 
ConocoPhillips is vigorously defending against
 
these lawsuits.
 
The
lawsuits brought by the Cities of San Francisco,
 
Oakland and New York have been dismissed by the district
courts and appeals are pending.
 
Lawsuits filed by other cities and counties
 
in California and Washington are
currently stayed pending resolution of the appeals
 
brought by the Cities of San Francisco and
 
Oakland to the
U.S. Court of Appeals for the Ninth Circuit.
 
Lawsuits filed in Maryland and Rhode
 
Island are proceeding in
state court while rulings in those matters, on the
 
issue of whether the matters should proceed
 
in state or federal
court, are on appeal to the U.S. Court of Appeals
 
for the Fourth Circuit and First Circuit, respectively.
 
55
 
 
Several Louisiana parishes and individual landowners have
 
filed lawsuits against oil and gas companies,
including ConocoPhillips, seeking compensatory damages
 
in connection with historical oil and gas operations
in Louisiana.
 
All parish lawsuits are stayed pending an
 
appeal to the Fifth Circuit Court of Appeals on the
issue of whether they will proceed in federal or state
 
court.
 
ConocoPhillips will vigorously defend against
these lawsuits.
 
 
 
Other
We
 
have deferred tax assets related to certain
 
accrued liabilities, loss carryforwards and
 
credit carryforwards.
 
Valuation
 
allowances have been established to reduce
 
these deferred tax assets to an amount that will,
 
more
likely than not, be realized.
 
Based on our historical taxable income,
 
our expectations for the future, and
available tax-planning strategies, management expects
 
the net deferred tax assets will be realized as
 
offsets to
reversing deferred tax liabilities.
 
 
CRITICAL ACCOUNTING ESTIMATES
 
The preparation of financial statements in conformity
 
with GAAP requires management to select
 
appropriate
accounting policies and to make estimates and
 
assumptions that affect the reported amounts of assets,
liabilities, revenues and expenses.
 
See Note 1—Accounting Policies, in the Notes to Consolidated
 
Financial
Statements, for descriptions of our major accounting policies.
 
Certain of these accounting policies involve
judgments and uncertainties to such an extent there
 
is a reasonable likelihood materially different amounts
would have been reported under different conditions, or if
 
different assumptions had been used.
 
These critical
accounting estimates are discussed with the Audit
 
and Finance Committee of the Board of Directors
 
at least
annually.
 
We believe the following discussions of critical accounting estimates, along with
 
the discussion of
deferred tax asset valuation allowances in this report,
 
address all important accounting areas where
 
the nature
of accounting estimates or assumptions is material due
 
to the levels of subjectivity and judgment
 
necessary to
account for highly uncertain matters or the susceptibility
 
of such matters to change.
 
Oil and Gas Accounting
 
Accounting for oil and gas exploratory activity is
 
subject to special accounting rules unique to the
 
oil and gas
industry.
 
The acquisition of geological and geophysical
 
seismic information, prior to the discovery of proved
reserves, is expensed as incurred, similar to accounting
 
for research and development costs.
 
However,
leasehold acquisition costs and exploratory well
 
costs are capitalized on the balance sheet pending
determination of whether proved oil and gas reserves
 
have been recognized.
 
Property Acquisition Costs
For individually significant leaseholds, management
 
periodically assesses for impairment based
 
on exploration
and drilling efforts to date.
 
For relatively small individual
 
leasehold acquisition costs, management exercises
judgment and determines a percentage probability
 
that the prospect ultimately will fail to find proved oil
 
and
gas reserves and pools that leasehold information
 
with others in the geographic area.
 
For prospects in areas
with limited, or no, previous exploratory drilling,
 
the percentage probability of ultimate failure is
 
normally
judged to be quite high.
 
This judgmental percentage is multiplied
 
by the leasehold acquisition cost, and that
product is divided by the contractual period of the leasehold
 
to determine a periodic leasehold impairment
charge that is reported in exploration expense.
 
This judgmental probability percentage is reassessed
 
and
adjusted throughout the contractual period of the leasehold
 
based on favorable or unfavorable exploratory
activity on the leasehold or on adjacent leaseholds,
 
and leasehold impairment amortization expense is
 
adjusted
prospectively.
 
 
At year-end 2019, the remaining $3.5 billion of net
 
capitalized unproved property costs consisted primarily
 
of
individually significant leaseholds, mineral rights
 
held in perpetuity by title ownership, exploratory
 
wells
currently being drilled, suspended exploratory wells,
 
and capitalized interest.
 
Of this amount, approximately
 
 
56
 
$2.1 billion is concentrated in 10 major development areas,
 
the majority of which are not expected to move
 
to
proved properties in 2020, and $0.6 billion is held for sale.
 
Management periodically assesses individually
significant leaseholds for impairment based on
 
the results of exploration and drilling efforts and the outlook
 
for
commercialization.
 
Exploratory Costs
For exploratory wells, drilling costs are temporarily capitalized,
 
or “suspended,” on the balance sheet, pending
a determination of whether potentially economic
 
oil and gas reserves have been discovered
 
by the drilling
effort to justify development.
 
 
If exploratory wells encounter potentially economic
 
quantities of oil and gas, the well costs remain
 
capitalized
on the balance sheet as long as sufficient progress assessing
 
the reserves and the economic and operating
viability of the project is being made.
 
The accounting notion of “sufficient progress” is a judgmental
 
area, but
the accounting rules do prohibit continued capitalization
 
of suspended well costs on the expectation
 
future
market conditions will improve or new technologies
 
will be found that would make the development
economically profitable.
 
Often, the ability to move into the development
 
phase and record proved reserves is
dependent on obtaining permits and government or
 
co-venturer approvals, the timing of which is ultimately
beyond our control.
 
Exploratory well costs remain suspended as long as we
 
are actively pursuing such
approvals and permits, and believe they will
 
be obtained.
 
Once all required approvals and permits have been
obtained, the projects are moved into the development
 
phase, and the oil and gas reserves are designated
 
as
proved reserves.
 
For complex exploratory discoveries,
 
it is not unusual to have exploratory wells
 
remain
suspended on the balance sheet for several years
 
while we perform additional appraisal drilling and
 
seismic
work on the potential oil and gas field or while we seek government
 
or co-venturer approval of development
plans or seek environmental permitting.
 
Once a determination is made the well did not
 
encounter potentially
economic oil and gas quantities, the well costs
 
are expensed as a dry hole and reported in exploration
 
expense.
 
 
Management reviews suspended well balances quarterly, continuously monitors
 
the results of the additional
appraisal drilling and seismic work, and expenses
 
the suspended well costs as a dry hole when it determines
the potential field does not warrant further investment
 
in the near term.
 
Criteria utilized in making this
determination include evaluation of the reservoir characteristics
 
and hydrocarbon properties, expected
development costs, ability to apply existing technology
 
to produce the reserves, fiscal terms, regulations
 
or
contract negotiations, and our expected return on
 
investment.
 
At year-end 2019, total suspended well costs
 
were $1,020 million, compared with $856 million at
 
year-end
2018.
 
For additional information on suspended wells,
 
including an aging analysis, see Note 8—Suspended
Wells and Other Exploration Expenses, in the Notes to Consolidated Financial
 
Statements.
 
Proved Reserves
 
Engineering estimates of the quantities of proved reserves
 
are inherently imprecise and represent only
approximate amounts because of the judgments involved
 
in developing such information.
 
Reserve estimates
are based on geological and engineering assessments
 
of in-place hydrocarbon volumes, the production plan,
historical extraction recovery and processing yield
 
factors, installed plant operating capacity
 
and approved
operating limits.
 
The reliability of these estimates at any point
 
in time depends on both the quality and
quantity of the technical and economic data and the
 
efficiency of extracting and processing the hydrocarbons.
 
 
Despite the inherent imprecision in these engineering
 
estimates, accounting rules require disclosure of
“proved” reserve estimates due to the importance
 
of these estimates to better understand
 
the perceived value
and future cash flows of a company’s operations.
 
There are several authoritative guidelines
 
regarding the
engineering criteria that must be met before estimated
 
reserves can be designated as “proved.”
 
Our
geosciences and reservoir engineering organization has policies
 
and procedures in place consistent with these
authoritative guidelines.
 
We have trained and experienced internal engineering personnel who estimate our
proved reserves held by consolidated companies, as
 
well as our share of equity affiliates.
 
 
57
 
Proved reserve estimates are adjusted annually in the fourth
 
quarter and during the year if significant changes
occur, and take into account recent production and subsurface information
 
about each field.
 
Also, as required
by current authoritative guidelines, the estimated
 
future date when an asset will be permanently shut
 
down for
economic reasons is based on 12-month average prices and
 
current costs.
 
This estimated date when production
will end affects the amount of estimated reserves.
 
Therefore, as prices and cost levels change from
 
year to
year, the estimate of proved reserves also changes.
 
Generally, our proved reserves decrease as prices decline
and increase as prices rise.
 
Our proved reserves include estimated quantities related
 
to PSCs, reported under the “economic interest”
method, as well as variable-royalty regimes, and are
 
subject to fluctuations in commodity
 
prices; recoverable
operating expenses; and capital costs.
 
If costs remain stable, reserve quantities
 
attributable to recovery of costs
will change inversely to changes in commodity prices.
 
We would expect reserves from these contracts to
decrease when product prices rise and increase
 
when prices decline.
 
 
The estimation of proved developed reserves also
 
is important to the income statement because
 
the proved
developed reserve estimate for a field serves as the denominator
 
in the unit-of-production calculation of the
DD&A of the capitalized costs for that asset.
 
At year-end 2019, the net book value of productive
 
PP&E
subject to a unit-of-production calculation was approximately
 
$35 billion and the DD&A recorded on these
assets in 2019 was approximately $5.8
 
billion.
 
The estimated proved developed reserves for
 
our consolidated
operations were 3.3 billion BOE at the end of 2018 and
 
3.2
 
billion BOE at the end of 2019.
 
If the estimates of
proved reserves used in the unit-of-production calculations
 
had been lower by 10 percent across all
calculations, before-tax DD&A in 2019 would have
 
increased by an estimated $642 million.
 
 
 
Impairments
 
Long-lived assets used in operations are assessed for
 
impairment whenever changes in facts
 
and circumstances
indicate a possible significant deterioration in future
 
cash flows expected to be generated by an asset
 
group and
annually in the fourth quarter following updates to corporate
 
planning assumptions.
 
If there is an indication
the carrying amount of an asset may not be recovered,
 
the asset is monitored by management through an
established process where changes to significant
 
assumptions such as prices, volumes and future development
plans are reviewed.
 
If, upon review, the sum of the undiscounted before-tax cash flows is less than
 
the
carrying value of the asset group, the carrying value is
 
written down to estimated fair value.
 
Individual assets
are grouped for impairment purposes based on a judgmental
 
assessment of the lowest level for which there are
identifiable cash flows that are largely independent of the cash flows
 
of other groups of assets—generally on a
field-by-field basis for E&P assets.
 
Because there usually is a lack of quoted market
 
prices for long-lived
assets, the fair value of impaired assets is typically
 
determined based on the present values of expected
 
future
cash flows using discount rates believed to be consistent
 
with those used by principal market participants,
 
or
based on a multiple of operating cash flow validated
 
with historical market transactions of similar assets where
possible.
 
The expected future cash flows used for impairment
 
reviews and related fair value calculations are
based on judgmental assessments of future production volumes,
 
commodity prices, operating costs and
 
capital
decisions, considering all available information at
 
the date of review.
 
Differing assumptions could affect the
timing and the amount of an impairment in any period.
 
See Note 9—Impairments, in the Notes to
Consolidated Financial Statements, for additional
 
information.
 
Investments in nonconsolidated entities accounted
 
for under the equity method are reviewed for
 
impairment
when there is evidence of a loss in value and annually
 
following updates to corporate planning assumptions.
 
Such evidence of a loss in value might include our
 
inability to recover the carrying amount, the
 
lack of
sustained earnings capacity which would justify
 
the current investment amount, or a current fair value less
 
than
the investment’s carrying amount.
 
When it is determined such a loss in value is
 
other than temporary, an
impairment charge is recognized for the difference between
 
the investment’s carrying value and its estimated
fair value.
 
When determining whether a decline in value is
 
other than temporary, management considers
factors such as the length of time and extent of
 
the decline, the investee’s financial condition and near-term
prospects, and our ability and intention to retain our
 
investment for a period that will be sufficient to allow
 
for
any anticipated recovery in the market value of the
 
investment.
 
Since quoted market prices are usually not
58
 
available, the fair value is typically based on the present
 
value of expected future cash flows using discount
rates believed to be consistent with those used by
 
principal market participants, plus market analysis
 
of
comparable assets owned by the investee, if appropriate.
 
Differing assumptions could affect the timing and the
amount of an impairment of an investment in any period.
 
See the “APLNG” section of Note 6—Investments,
Loans and Long-Term Receivables, in the Notes to Consolidated Financial Statements,
 
for additional
information.
 
Asset Retirement Obligations and Environmental Costs
 
Under various contracts, permits and regulations,
 
we have material legal obligations to remove tangible
equipment and restore the land or seabed at the
 
end of operations at operational sites.
 
Our largest asset
removal obligations involve plugging and abandonment
 
of wells, removal and disposal of offshore oil
 
and gas
platforms around the world,
 
as well as oil and gas production
 
facilities and pipelines in Alaska.
 
The fair values
of obligations for dismantling and removing these facilities
 
are recorded as a liability and an increase to PP&E
at the time of installation of the asset based on estimated
 
discounted costs.
 
Estimating future asset removal
costs is difficult.
 
Most of these removal obligations are many
 
years, or decades, in the future and the contracts
and regulations often have vague descriptions
 
of what removal practices and criteria must
 
be met when the
removal event actually occurs.
 
Asset removal technologies and costs, regulatory
 
and other compliance
considerations, expenditure timing, and other inputs into
 
valuation of the obligation, including discount
 
and
inflation rates, are also subject to change.
 
 
Normally, changes in asset removal obligations are reflected in the income statement
 
as increases or decreases
to DD&A over the remaining life of the assets.
 
However, for assets at or nearing the end of their operations, as
well as previously sold assets for which we retained the
 
asset removal obligation, an increase in the asset
removal obligation can result in an immediate charge to earnings, because
 
any increase in PP&E due to the
increased obligation would immediately be subject
 
to impairment, due to the low fair value of
 
these properties.
 
 
In addition to asset removal obligations, under the
 
above or similar contracts, permits and regulations, we
 
have
certain environmental-related projects.
 
These are primarily related to remediation activities
 
required by
Canada and various states
 
within the U.S. at exploration and production
 
sites.
 
Future environmental
remediation costs are difficult to estimate because they are subject
 
to change due to such factors as the
uncertain magnitude of cleanup costs, the unknown
 
time and extent of such remedial actions that
 
may be
required, and the determination of our liability
 
in proportion to that of other responsible parties.
 
See Note
10—Asset Retirement Obligations and Accrued Environmental
 
Costs, in the Notes to Consolidated Financial
Statements, for additional information.
 
Projected Benefit Obligations
 
Determination of the projected benefit obligations for our
 
defined benefit pension and postretirement plans
 
are
important to the recorded amounts for such obligations
 
on the balance sheet and to the amount of benefit
expense in the income statement.
 
The actuarial determination of projected benefit obligations
 
and company
contribution requirements involves judgment about
 
uncertain future events, including estimated retirement
dates, salary levels at retirement, mortality rates, lump-sum
 
election rates, rates of return on plan assets, future
health care cost-trend rates, and rates of utilization
 
of health care services by retirees.
 
Due to the specialized
nature of these calculations, we engage outside actuarial
 
firms to assist in the determination of these projected
benefit obligations and company contribution requirements.
 
For Employee Retirement Income Security Act-
governed pension plans, the actuary exercises fiduciary
 
care on behalf of plan participants in the determination
of the judgmental assumptions used in determining
 
required company contributions into the plans.
 
Due to
differing objectives and requirements between financial
 
accounting rules and the pension plan funding
regulations promulgated by governmental agencies,
 
the actuarial methods and assumptions
 
for the two
purposes differ in certain important respects.
 
Ultimately, we will be required to fund all vested benefits under
pension and postretirement benefit plans not funded by
 
plan assets or investment returns, but the
 
judgmental
assumptions used in the actuarial calculations significantly
 
affect periodic financial statements and funding
patterns over time.
 
Projected benefit obligations are particularly
 
sensitive to the discount rate assumption.
 
A
59
 
100 basis-point decrease in the discount rate assumption
 
would increase projected benefit obligations by
$1,000 million.
 
Benefit expense is sensitive to the discount
 
rate and return on plan assets assumptions.
 
A
100 basis-point decrease in the discount rate assumption
 
would increase annual benefit expense by
$100 million, while a 100 basis-point decrease in the
 
return on plan assets assumption would increase
 
annual
benefit expense by $60
 
million.
 
In determining the discount rate, we use yields on high-quality
 
fixed income
investments matched to the estimated benefit cash
 
flows of our plans.
 
We
 
are also exposed to the possibility
that lump sum retirement benefits taken from pension
 
plans during the year could exceed the
 
total of service
and interest components of annual pension expense and
 
trigger accelerated recognition of a portion
 
of
unrecognized net actuarial losses and gains.
 
These benefit payments are based on decisions
 
by plan
participants and are therefore difficult to predict.
 
In the event there is a significant reduction
 
in the expected
years of future service of present employees or the elimination
 
of the accrual of defined benefits for some
 
or all
of their future services for a significant number of
 
employees, we could recognize a curtailment gain
 
or loss.
 
See Note 18—Employee Benefit Plans, in the Notes to
 
Consolidated Financial Statements, for additional
information.
 
Contingencies
A number of claims and lawsuits are made against the
 
company arising in the ordinary course of
 
business.
 
Management exercises judgment related to accounting
 
and disclosure of these claims which includes losses,
damages, and underpayments associated with
 
environmental remediation, tax, contracts, and other
 
legal
disputes.
 
As we learn new facts concerning contingencies,
 
we reassess our position both with respect to
amounts recognized and disclosed considering changes
 
to the probability of additional losses and
 
potential
exposure.
 
However, actual losses can and do vary from estimates for a variety
 
of reasons including legal,
arbitration, or other third-party decisions; settlement discussions;
 
evaluation of scope of damages;
interpretation of regulatory or contractual terms;
 
expected timing of future actions; and proportion of
 
liability
shared with other responsible parties.
 
Estimated future costs related to contingencies
 
are subject to change as
events evolve and as additional information becomes
 
available during the administrative and litigation
processes.
 
For additional information on contingent liabilities,
 
see the “Contingencies” section within “Capital
Resources and Liquidity” and Note 13—Contingencies and
 
Commitments.
60
 
CAUTIONARY STATEMENT
 
FOR THE PURPOSES OF THE “SAFE HARBOR”
 
PROVISIONS OF
THE PRIVATE
 
SECURITIES LITIGATION REFORM ACT OF 1995
 
This report includes forward-looking statements within
 
the meaning of Section 27A of the Securities
 
Act of
1933 and Section 21E of the Securities Exchange Act
 
of 1934.
 
All statements other than statements of
historical fact included or incorporated by reference
 
in this report, including, without limitation, statements
regarding our future financial position, business strategy, budgets, projected revenues,
 
projected costs and
plans, and objectives of management for future operations,
 
are forward-looking statements.
 
Examples of
forward-looking statements contained in this report include
 
our expected production growth and outlook
 
on the
business environment generally, our expected capital budget and capital expenditures,
 
and discussions
concerning future dividends.
 
You
 
can often identify our forward-looking statements by
 
the words “anticipate,”
“estimate,” “believe,” “budget,” “continue,” “could,”
 
“intend,” “may,” “plan,” “potential,” “predict,” “seek,”
“should,” “will,” “would,” “expect,” “objective,” “projection,”
 
“forecast,” “goal,” “guidance,” “outlook,”
“effort,” “target” and similar expressions.
 
We
 
based the forward-looking statements on
 
our current expectations, estimates and projections
 
about
ourselves and the industries in which we operate in
 
general.
 
We
 
caution you these statements are not
guarantees of future performance as they involve
 
assumptions that, while made in good faith, may prove
 
to be
incorrect, and involve risks and uncertainties we cannot
 
predict.
 
In addition, we based many of these forward-
looking statements on assumptions about future events
 
that may prove to be inaccurate.
 
Accordingly, our
actual outcomes and results may differ materially from what
 
we have expressed or forecast in the forward-
looking statements.
 
Any differences could result from a variety of factors,
 
including, but not limited to, the
following:
 
 
●
 
Fluctuations in crude oil, bitumen, natural gas, LNG
 
and NGLs prices, including a prolonged decline
in these prices relative to historical or future expected
 
levels.
●
 
The impact of significant declines in prices for
 
crude oil, bitumen, natural gas, LNG and NGLs,
 
which
may result in recognition of impairment costs on our
 
long-lived assets, leaseholds and
nonconsolidated equity investments.
●
 
Potential failures or delays in achieving expected reserve
 
or production levels from existing and future
oil and gas developments, including due to operating hazards,
 
drilling risks and the inherent
uncertainties in predicting reserves and reservoir
 
performance.
●
 
Reductions in reserves replacement rates, whether as
 
a result of the significant declines in commodity
prices or otherwise.
●
 
Unsuccessful exploratory drilling activities or the
 
inability to obtain access to exploratory
 
acreage.
●
 
Unexpected changes in costs or technical requirements
 
for constructing, modifying or operating E&P
facilities.
●
 
Legislative and regulatory initiatives addressing environmental
 
concerns, including initiatives
addressing the impact of global climate change
 
or further regulating hydraulic fracturing, methane
emissions, flaring or water disposal.
●
 
Lack of, or disruptions in, adequate and reliable transportation
 
for our crude oil, bitumen, natural gas,
LNG and NGLs.
●
 
Inability to timely obtain or maintain permits,
 
including those necessary for construction, drilling
and/or development, or inability to make capital expenditures
 
required to maintain compliance with
any necessary permits or applicable laws or regulations.
●
 
Failure to complete definitive agreements and feasibility
 
studies for, and to complete construction of,
announced and future exploration and production and
 
LNG development in a timely manner (if at all)
or on budget.
●
 
Potential disruption or interruption of our operations
 
due to accidents, extraordinary weather events,
civil unrest, political events, war, global health epidemics,
 
terrorism, cyber attacks, and information
technology failures, constraints or disruptions.
●
 
Changes in international monetary conditions and foreign
 
currency exchange rate fluctuations.
●
 
Changes in international trade relationships, including
 
the imposition of trade restrictions or tariffs
61
 
relating to crude oil, bitumen, natural gas, LNG, NGLs
 
and any materials or products (such as
aluminum and steel) used in the operation of our
 
business.
●
 
Substantial investment in and development use
 
of, competing or alternative energy sources, including
as a result of existing or future environmental rules and
 
regulations.
●
 
Liability for remedial actions, including removal and
 
reclamation obligations, under existing or future
environmental regulations and litigation.
●
 
Significant operational or investment changes imposed
 
by existing or future environmental statutes
and regulations, including international agreements
 
and national or regional legislation and regulatory
measures to limit or reduce GHG emissions.
●
 
Liability resulting from litigation or our failure to
 
comply with applicable laws and regulations.
 
●
 
General domestic and international economic and
 
political developments, including armed hostilities;
expropriation of assets; changes in governmental
 
policies relating to crude oil, bitumen, natural
 
gas,
LNG and NGLs pricing, regulation or taxation; the impact
 
of and uncertainty surrounding the U.K.’s
decision to withdraw from the EU; and other political,
 
economic or diplomatic developments.
●
 
Volatility
 
in the commodity futures markets.
●
 
Changes in tax and other laws, regulations (including
 
alternative energy mandates), or royalty rules
applicable to our business, including changes resulting
 
from the implementation and interpretation
 
of
the Tax Cuts and Jobs Act.
●
 
Competition and consolidation in the oil and gas
 
E&P industry.
●
 
Any limitations on our access to capital or increase
 
in our cost of capital, including as a result
 
of
illiquidity or uncertainty in domestic or international
 
financial markets.
●
 
Our inability to execute, or delays in the completion,
 
of any asset dispositions or acquisitions we elect
to pursue.
 
●
 
Potential failure to obtain, or delays in obtaining, any
 
necessary regulatory approvals for asset
dispositions or acquisitions, or that such approvals
 
may require modification to the terms of
 
the
transactions or the operation of our remaining business.
●
 
Potential disruption of our operations as a result
 
of asset dispositions or acquisitions, including
 
the
diversion of management time and attention.
●
 
Our inability to deploy the net proceeds from any asset
 
dispositions we undertake in the manner and
timeframe we currently anticipate, if at all.
●
 
Our inability to liquidate the common stock issued to us
 
by Cenovus Energy as part of our sale of
certain assets in western Canada at prices we deem
 
acceptable, or at all.
●
 
The operation and financing of our joint ventures.
●
 
The ability of our customers and other contractual counterparties
 
to satisfy their obligations to us,
including our ability to collect payments when due
 
from the government of Venezuela or PDVSA.
 
●
 
Our inability to realize anticipated cost savings and expenditure
 
reductions.
●
 
The risk factors generally described in Item 1A—Risk
 
Factors in our 2019 Annual Report on Form
10-K filed with the SEC on February 18, 2020, and any
 
additional risks described in our other filings
with the SEC.
 
62
 
Item 8.
 
FINANCIAL STATEMENTS
 
AND SUPPLEMENTARY DATA
 
 
 
 
CONOCOPHILLIPS
 
 
 
INDEX TO FINANCIAL STATEMENTS
Page
Report of Management ............................................................................................................................
 
63
Reports of Independent Registered Public Accounting
 
Firm..................................................................
 
64
Consolidated Income Statement for the years ended December
 
31, 2019, 2018 and 2017 ....................
 
68
Consolidated Statement of Comprehensive Income for
 
the years ended
 
December 31, 2019, 2018 and 2017 ..................................................................................................
 
69
Consolidated Balance Sheet at December 31,
 
2019 and 2018 ................................................................
 
70
Consolidated Statement of Cash Flows for the years
 
ended December 31, 2019,
 
2018 and 2017 .........
 
71
Consolidated Statement of Changes in Equity for
 
the years ended
December 31, 2019, 2018 and 2017 ..................................................................................................
 
72
Notes to Consolidated Financial Statements
 
............................................................................................
 
73
Supplementary Information
Oil and Gas Operations ..............................................................................................................
 
137
Selected Quarterly Financial Data ..............................................................................................
 
165
Condensed Consolidating Financial Information
 
.......................................................................
 
166
 
 
63
 
Report of Management
 
 
Management prepared, and is responsible for, the consolidated financial
 
statements and the other information
appearing in this annual report.
 
The consolidated financial statements present
 
fairly the company’s financial
position, results of operations and cash flows in conformity
 
with accounting principles generally accepted
 
in
the United States.
 
In preparing its consolidated financial statements,
 
the company includes amounts that are
based on estimates and judgments management believes
 
are reasonable under the circumstances.
 
The
company’s financial statements have been audited by Ernst & Young LLP,
 
an independent registered public
accounting firm appointed by the Audit and Finance Committee
 
of the Board of Directors and ratified by
stockholders.
 
Management has made available to Ernst
 
& Young LLP all of the company’s financial records
and related data, as well as the minutes of stockholders’
 
and directors’ meetings.
 
Assessment of Internal Control Over Financial Reporting
Management is also responsible for establishing and maintaining
 
adequate internal control over financial
reporting.
 
ConocoPhillips’ internal control system
 
was designed to provide reasonable assurance to the
company’s management and directors regarding the preparation and fair presentation
 
of published financial
statements.
 
All internal control systems, no matter how well
 
designed, have inherent limitations.
 
Therefore, even those
systems determined to be effective can provide only reasonable
 
assurance with respect to financial statement
preparation and presentation.
 
 
Management assessed the effectiveness of the company’s internal control over financial
 
reporting as of
December 31, 2019.
 
In making this assessment, it
 
used the criteria set forth by the Committee of
 
Sponsoring
Organizations of the Treadway Commission in
Internal Control—Integrated Framework (2013)
.
 
Based on our
assessment, we believe the company’s internal control over financial reporting
 
was effective as of
December 31, 2019.
 
Ernst & Young LLP has issued an audit report on the company’s internal control over financial reporting as of
December 31, 2019, and their report is included herein.
 
 
/s/ Ryan M. Lance
/s/ Don E. Wallette, Jr.
Ryan M. Lance
 
Don E. Wallette, Jr.
Chairman and
Chief Executive Officer
 
Executive Vice President and
 
Chief Financial Officer
 
 
 
February 18, 2020
 
64
 
Report of Independent Registered Public Accounting
 
Firm
 
 
To the Stockholders and the Board of Directors of ConocoPhillips
 
Opinion on the Financial Statements
 
We
 
have audited the accompanying consolidated
 
balance sheets of ConocoPhillips (the Company)
 
as of
December 31, 2019 and 2018, the related consolidated
 
income statement, consolidated statements
 
of
comprehensive income, changes in equity and cash flows
 
for each of the three years in the period ended
December 31, 2019, and the related notes, condensed
 
consolidating financial information listed in the Index
 
at
Item 8, and financial statement schedule listed in
 
Item 15(a) (collectively referred to as the
 
“consolidated
financial statements”). In our opinion, the consolidated
 
financial statements present fairly, in all material
respects, the financial position of the Company at
 
December 31, 2019 and 2018, and the results
 
of its
operations and its cash flows for each of the three
 
years in the period ended December 31, 2019, in
 
conformity
with U.S. generally accepted accounting principles.
 
We
 
also have audited, in accordance with the standards
 
of the Public Company Accounting
 
Oversight Board
(United States) (PCAOB), the Company’s internal control over financial
 
reporting as of December 31, 2019,
based on criteria established in Internal Control–Integrated
 
Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission (2013 framework) and our report
 
dated February 18, 2020,
expressed an unqualified opinion thereon.
 
Basis for Opinion
These financial statements are the responsibility
 
of the Company’s management. Our responsibility is to
express an opinion on the Company’s financial statements based on our
 
audits. We are a public accounting
firm registered with the PCAOB and are required to be
 
independent with respect to the Company in
accordance with the U.S. federal securities laws and
 
the applicable rules and regulations of the Securities
 
and
Exchange Commission and the PCAOB.
 
We
 
conducted our audits in accordance with the standards
 
of the PCAOB. Those standards require that we
plan and perform the audit to obtain reasonable assurance
 
about whether the financial statements are free of
material misstatement, whether due to error or fraud.
 
Our audits included performing procedures to
 
assess the
risks of material misstatement of the financial statements,
 
whether due to error or fraud, and performing
procedures that respond to those risks. Such procedures
 
included examining, on a test basis, evidence
regarding the amounts and disclosures in the financial
 
statements. Our audits also included evaluating
 
the
accounting principles used and significant estimates
 
made by management, as well as evaluating the
 
overall
presentation of the financial statements. We believe that our audits provide a reasonable
 
basis for our opinion.
 
Critical Audit Matters
The critical audit matters communicated below are
 
matters arising from the current period audit of the
consolidated financial statements that were communicated
 
or required to be communicated to the Audit
 
and
Finance Committee and that: (1) relate to accounts
 
or disclosures that are material to the consolidated
 
financial
statements and (2) involved our especially challenging,
 
subjective or complex judgments. The
 
communication
of critical audit matters does not alter in any way
 
our opinion on the consolidated financial statements,
 
taken as
a whole, and we are not, by communicating the
 
critical audit matters below, providing separate opinions on the
critical audit matters or on the accounts or disclosures to
 
which they relate.
 
65
 
Accounting for asset retirement obligations for
 
certain offshore properties
Description of
the Matter
At December 31, 2019, the asset retirement obligation
 
(“ARO”) balance totaled $6.2
billion. As further described in Note 10, the Company
 
records AROs in the period in
which they are incurred, typically when the asset is
 
installed at the production location.
The estimation of obligations related to certain offshore
 
assets requires significant
judgment given the magnitude of these removal costs
 
and higher estimation uncertainty
related to the removal plan and costs. Furthermore, given
 
certain of these assets are
nearing the end of their operations, the impact
 
of changes in these AROs may result in a
material impact to earnings given the relatively short
 
remaining useful lives of the assets.
Auditing the Company’s AROs for the obligations identified above is complex
 
and
highly judgmental due to the significant estimation required
 
by management in
determining the obligations. In particular, the estimates were
 
sensitive to significant
subjective assumptions such as removal cost estimates
 
and end of field life, which are
affected by expectations about future market or economic
 
conditions.
How We
Addressed the
Matter in Our
Audit
We
 
obtained an understanding, evaluated the
 
design and tested the operating
effectiveness of the Company’s internal controls over its ARO estimation process,
including management’s review of the significant assumptions that have a
 
material effect
on the determination of the obligations. We also tested management’s controls over the
completeness and accuracy of the financial data
 
used in the valuation.
To test the AROs for the obligations identified above, our audit procedures included,
among others, assessing the significant assumptions and
 
inputs used in the valuation,
including removal cost estimates and end of field
 
life assumptions. For example, we
evaluated removal cost estimates by comparing to settlements
 
and recent removal
activities and costs. We also compared end of field life assumptions to production
forecasts.
 
We involved our internal specialists in testing the underlying removal cost
estimates.
Depreciation, depletion and amortization of proved oil
 
and gas properties
Description of
the Matter
At December 31, 2019, the net book value of the Company’s properties,
 
plants and
equipment was $42.3 billion, and depreciation, depletion
 
and amortization (DD&A)
expense was $6.1 billion for the year then ended. As
 
described in Note 1, DD&A of
properties, plants and equipment on producing hydrocarbon
 
properties and certain
pipeline and LNG assets (those which are expected
 
to have a declining utilization
pattern) are determined by the unit-of-production method
 
based on proved oil and gas
reserves, as estimated by the Company’s internal reservoir engineers. Proved
 
oil and gas
reserve estimates are based on geological and engineering
 
assessments of in-place
hydrocarbon volumes, the production plan, historical
 
extraction recovery and processing
yield factors, installed plant operating capacity
 
and approved operating limits. Significant
judgment is required by the Company’s internal reservoir engineers in evaluating
geological and engineering data when estimating
 
proved oil and gas reserves. Estimating
reserves also requires the selection of inputs, including
 
oil and gas price assumptions,
future operating and capital costs assumptions and tax
 
rates by jurisdiction, among
others. Because of the complexity involved in estimating
 
oil and gas reserves,
management also used a third-party petroleum engineering
 
firm to perform a review of
the processes and controls used by the Company’s internal reservoir
 
engineers to
determine estimates of proved oil and gas reserves.
66
 
Auditing the Company’s DD&A calculation is complex because of the use
 
of the work of
the internal reservoir engineers and third-party petroleum
 
engineering firm and the
evaluation of management’s determination of the inputs described above used
 
by the
internal reservoir engineers in estimating proved oil
 
and gas reserves.
 
How We
Addressed the
Matter in Our
Audit
We
 
obtained an understanding, evaluated the
 
design and tested the operating
effectiveness of the Company’s internal controls over its process to calculate DD&A,
including management’s controls over the completeness and accuracy of
 
the financial
data provided to the internal reservoir engineers for
 
use in estimating proved oil and gas
reserves.
Our audit procedures included, among others,
 
evaluating the professional qualifications
and objectivity of the Company’s internal reservoir engineers primarily responsible
 
for
overseeing the preparation of the reserve estimates and
 
the third-party petroleum
engineering firm used to review the Company’s processes and controls. In
 
addition, in
assessing whether we can use the work of the internal
 
reservoir engineers, we evaluated
the completeness and accuracy of the financial data
 
and inputs described above used by
the internal reservoir engineers in estimating proved
 
oil and gas reserves by agreeing
them to source documentation and we identified and
 
evaluated corroborative and
contrary evidence. For proved undeveloped reserves,
 
we evaluated management’s
development plan for compliance with the SEC rule
 
that undrilled locations are
scheduled to be drilled within five years, unless
 
specific circumstances justify a longer
time, by assessing consistency of the development projections
 
with the Company’s drill
plan. We also tested the accuracy of the DD&A calculations, including comparing
 
the
proved oil and gas reserve amounts used in the calculation
 
to the Company’s reserve
report.
 
 
/s/ Ernst & Young LLP
 
We
 
have served as ConocoPhillips’ auditor
 
since 1949.
 
Houston, Texas
February 18, 2020, except as it relates to the effects of the
 
change in segments described in Note 25, as to
which the date is November 16, 2020
 
 
 
67
 
Report of Independent Registered Public
 
Accounting Firm
 
 
To the Stockholders and the Board of Directors of ConocoPhillips
 
Opinion on Internal Control over Financial
 
Reporting
We have audited ConocoPhillips’ internal control over financial reporting
 
as of December 31, 2019, based on
criteria established in Internal Control–Integrated
 
Framework issued by the
 
Committee of Sponsoring Organizations
of the Treadway Commission (2013 framework)
 
(the COSO criteria). In our opinion,
 
ConocoPhillips (the Company)
maintained, in all material respects, effective
 
internal control over financial
 
reporting as of December 31,
 
2019,
based on the COSO criteria.
 
We also have audited, in accordance with the standards of
 
the Public Company Accounting
 
Oversight Board (United
States) (PCAOB), the consolidated balance
 
sheets of the Company as
 
of December 31, 2019 and
 
2018, the related
consolidated income statement,
 
consolidated statements of comprehensive
 
income, changes in equity and
 
cash flows
for each of the three years in the period
 
ended December 31, 2019,
 
and the related notes, condensed
 
consolidating
financial information listed in the
 
Index at Item 8, and financial
 
statement schedule listed in Item
 
15(a) and our
report dated February 18, 2020, expressed
 
an unqualified opinion thereon.
 
Basis for Opinion
The Company’s management is responsible for maintaining
 
effective internal control over financial reporting
 
and
for its assessment of the effectiveness of internal
 
control over financial reporting included
 
under the heading
“Assessment of Internal Control
 
Over Financial Reporting” in the accompanying
 
“Report of Management.” Our
responsibility is to express an opinion
 
on the Company’s internal control over financial
 
reporting based on our audit.
We are a public accounting firm registered with the PCAOB
 
and are required to be independent with
 
respect to the
Company in accordance with the U.S.
 
federal securities laws and
 
the applicable rules and regulations
 
of the
Securities and Exchange Commission
 
and the PCAOB.
 
We conducted our audit in accordance with the standards of the
 
PCAOB. Those standards
 
require that we plan and
perform the audit to obtain reasonable
 
assurance about whether effective internal
 
control over financial reporting
was maintained in all material respects.
 
 
Our audit included obtaining an
 
understanding of internal control
 
over financial reporting, assessing
 
the risk that a
material weakness exists, testing
 
and evaluating the design and
 
operating effectiveness of internal
 
control based on
the assessed risk, and performing such
 
other procedures as we considered
 
necessary in the circumstances.
 
We
believe that our audit provides a reasonable
 
basis for our opinion.
 
Definition and Limitations of Internal
 
Control Over Financial Reporting
A company’s internal control over financial reporting
 
is a process designed to provide
 
reasonable assurance
regarding the reliability of financial
 
reporting and the preparation
 
of financial statements
 
for external purposes in
accordance with generally accepted accounting
 
principles. A company’s internal control over financial
 
reporting
includes those policies and procedures
 
that (1) pertain to the maintenance
 
of records that, in reasonable
 
detail,
accurately and fairly reflect the transactions
 
and dispositions of the assets
 
of the company; (2) provide reasonable
assurance that transactions are recorded
 
as necessary to permit preparation
 
of financial statements in accordance
with generally accepted accounting
 
principles, and that receipts and expenditures
 
of the company are being made
only in accordance with authorizations
 
of management and directors
 
of the company; and (3) provide
 
reasonable
assurance regarding prevention or
 
timely detection of unauthorized acquisition,
 
use, or disposition of the company’s
assets that could have a material effect on the
 
financial statements.
 
Because of its inherent limitations,
 
internal control over financial
 
reporting may not prevent or detect
 
misstatements.
Also, projections of any evaluation of
 
effectiveness to future periods are
 
subject to the risk that controls may
 
become
inadequate because of changes in conditions,
 
or that the degree of compliance
 
with the policies or procedures
 
may
deteriorate.
 
/s/ Ernst & Young LLP
 
Houston, Texas
February 18, 2020
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
68
 
Consolidated Income Statement
ConocoPhillips
Years
 
Ended December 31
Millions of Dollars
2019
2018
2017
Revenues and Other Income
Sales and other operating revenues
$
32,567
36,417
29,106
Equity in earnings of affiliates
779
1,074
772
Gain on dispositions
1,966
1,063
2,177
Other income
 
1,358
173
529
Total Revenues and Other Income
36,670
38,727
32,584
Costs and Expenses
Purchased commodities
11,842
14,294
12,475
Production and operating expenses
5,322
5,213
5,162
Selling, general and administrative
 
expenses
556
401
427
Exploration expenses
743
369
934
Depreciation, depletion and amortization
6,090
5,956
6,845
Impairments
405
27
6,601
Taxes other than income taxes
953
1,048
809
Accretion on discounted liabilities
326
353
362
Interest and debt expense
778
735
1,098
Foreign currency transaction (gains)
 
losses
66
(17)
35
Other expenses
65
375
451
Total Costs and Expenses
27,146
28,754
35,199
Income (loss) before income taxes
9,524
9,973
(2,615)
Income tax provision (benefit)
2,267
3,668
(1,822)
Net income (loss)
7,257
6,305
(793)
Less: net income attributable to noncontrolling
 
interests
(68)
(48)
(62)
Net Income (Loss) Attributable to
 
ConocoPhillips
$
7,189
6,257
(855)
Net Income (Loss) Attributable to
 
ConocoPhillips Per Share
of Common Stock
(dollars)
Basic
$
6.43
5.36
(0.70)
Diluted
6.40
5.32
(0.70)
Average Common Shares Outstanding
(in thousands)
Basic
1,117,260
1,166,499
1,221,038
Diluted
1,123,536
1,175,538
1,221,038
See Notes to Consolidated
 
Financial Statements.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
69
 
Consolidated Statement of Comprehensive Income
ConocoPhillips
Years
 
Ended December 31
Millions of Dollars
2019
2018
2017
Net Income (Loss)
$
7,257
6,305
(793)
Other comprehensive income (loss)
Defined benefit plans
Prior service credit (cost) arising
 
during the period
-
(7)
2
Reclassification adjustment for amortization
 
of prior
service credit included in net income
 
(loss)
(35)
(40)
(38)
Net change
(35)
(47)
(36)
Net actuarial gain (loss) arising during
 
the period
(55)
(150)
19
Reclassification adjustment for amortization
 
of net
actuarial losses included in net income
 
(loss)
146
279
247
Net change
91
129
266
Nonsponsored plans*
(3)
(1)
(2)
Income taxes on defined benefit plans
(2)
(42)
(81)
Defined benefit plans, net of tax
51
39
147
Unrealized holding loss on securities
-
-
(58)
Unrealized loss on securities, net of
 
tax
-
-
(58)
Foreign currency translation adjustments
699
(645)
586
Income taxes on foreign currency
 
translation adjustments
(4)
3
-
Foreign currency translation adjustments,
 
net of tax
695
(642)
586
Other Comprehensive Income (Loss), Net
 
of Tax
746
(603)
675
Comprehensive Income (Loss)
8,003
5,702
(118)
Less: comprehensive income attributable
 
to noncontrolling interests
(68)
(48)
(62)
Comprehensive Income (Loss) Attributable
 
to ConocoPhillips
$
7,935
5,654
(180)
*Plans for which ConocoPhillips
 
is not the primary obligor
—
primarily those administered
 
by equity affiliates.
See Notes to Consolidated
 
Financial Statements.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
70
 
Consolidated Balance Sheet
 
ConocoPhillips
At December 31
Millions of Dollars
2019
2018
Assets
Cash and cash equivalents
$
5,088
5,915
Short-term investments
3,028
248
Accounts and notes receivable (net
 
of allowance of $
13
 
million in 2019
and $
25
 
million in 2018)
3,267
3,920
Accounts and notes receivable—related
 
parties
134
147
Investment in Cenovus Energy
2,111
1,462
Inventories
1,026
1,007
Prepaid expenses and other current
 
assets
2,259
575
Total Current Assets
16,913
13,274
Investments and long-term receivables
8,687
9,329
Loans and advances—related parties
219
335
Net properties, plants and equipment
 
(net of accumulated depreciation,
 
depletion
and amortization of $
55,477
 
million in 2019 and $
64,899
 
million in 2018)
42,269
45,698
Other assets
2,426
1,344
Total Assets
$
70,514
69,980
Liabilities
Accounts payable
$
3,176
3,863
Accounts payable—related parties
24
32
Short-term debt
105
112
Accrued income and other taxes
1,030
1,320
Employee benefit obligations
663
809
Other accruals
2,045
1,259
Total Current Liabilities
7,043
7,395
Long-term debt
14,790
14,856
Asset retirement obligations and accrued
 
environmental costs
5,352
7,688
Deferred income taxes
4,634
5,021
Employee benefit obligations
1,781
1,764
Other liabilities and deferred credits
1,864
1,192
Total Liabilities
35,464
37,916
Equity
Common stock (
2,500,000,000
 
shares authorized at $
0.01
 
par value)
Issued (2019—
1,795,652,203
 
shares; 2018—
1,791,637,434
 
shares)
Par value
18
18
Capital in excess of par
46,983
46,879
Treasury stock (at cost: 2019—
710,783,814
 
shares; 2018—
653,288,213
 
shares)
(46,405)
(42,905)
Accumulated other comprehensive
 
loss
(5,357)
(6,063)
Retained earnings
39,742
34,010
Total Common Stockholders’ Equity
34,981
31,939
Noncontrolling interests
69
125
Total Equity
35,050
32,064
Total Liabilities and Equity
$
70,514
69,980
See Notes to Consolidated
 
Financial Statements.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
71
 
Consolidated Statement of Cash Flows
ConocoPhillips
Years
 
Ended December 31
Millions of Dollars
2019
2018
2017
Cash Flows From Operating Activities
Net income (loss)
$
7,257
6,305
(793)
Adjustments to reconcile net income
 
(loss) to net cash provided by
 
operating activities
Depreciation, depletion and amortization
6,090
5,956
6,845
Impairments
405
27
6,601
Dry hole costs and leasehold impairments
421
95
566
Accretion on discounted liabilities
326
353
362
Deferred taxes
(444)
283
(3,681)
Undistributed equity earnings
594
152
(232)
Gain on dispositions
(1,966)
(1,063)
(2,177)
Other
(1,000)
191
(429)
Working capital adjustments
Decrease (increase) in accounts and
 
notes receivable
505
235
(886)
Decrease (increase) in inventories
(67)
86
(55)
Decrease (increase) in prepaid expenses
 
and other current assets
37
(55)
69
Increase (decrease) in accounts payable
(378)
(52)
265
Increase (decrease) in taxes and other
 
accruals
(676)
421
622
Net Cash Provided by Operating
 
Activities
11,104
12,934
7,077
Cash Flows From Investing Activities
Capital expenditures and investments
(6,636)
(6,750)
(4,591)
Working capital changes associated with investing activities
(103)
(68)
132
Proceeds from asset dispositions
3,012
1,082
13,860
Net sales (purchases) of investments
(2,910)
1,620
(1,790)
Collection of advances/loans—related
 
parties
127
119
115
Other
(108)
154
36
Net Cash Provided by (Used in) Investing
 
Activities
(6,618)
(3,843)
7,762
Cash Flows From Financing Activities
Repayment of debt
(80)
(4,995)
(7,876)
Issuance of company common stock
(30)
121
(63)
Repurchase of company common
 
stock
(3,500)
(2,999)
(3,000)
Dividends paid
(1,500)
(1,363)
(1,305)
Other
(119)
(123)
(112)
Net Cash Used in Financing Activities
(5,229)
(9,359)
(12,356)
Effect of Exchange Rate Changes
 
on Cash, Cash Equivalents
 
and Restricted Cash
(46)
(117)
232
Net Change in Cash, Cash Equivalents
 
and Restricted Cash
(789)
(385)
2,715
Cash, cash equivalents and restricted cash
 
at beginning of period
6,151
6,536
3,610
Cash, Cash Equivalents and Restricted
 
Cash at End of Period
$
5,362
6,151
6,325
Restricted cash of $
90
 
million and $
184
 
million are included
 
in the “Prepaid expenses
 
and other current
 
assets” and “Other assets” lines,
respectively,
 
of our Consolidated Balance
 
Sheet as of December 31, 2019.
Restricted cash totaling $
236
 
million is included in the “Other assets” line of
 
our Consolidated
 
Balance Sheet as of December 31,
 
2018.
See Notes to Consolidated
 
Financial Statements.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
72
 
Consolidated Statement of Changes in Equity
 
ConocoPhillips
Millions of Dollars
Attributable to ConocoPhillips
Common Stock
Par
Value
Capital in
Excess of
Par
Treasury
Stock
Accum. Other
Comprehensive
Income (Loss)
Retained
Earnings
Non-
Controlling
Interests
Total
December 31, 2016
$
18
46,507
(36,906)
(6,193)
31,548
252
35,226
Net income (loss)
(855)
62
(793)
Other comprehensive income
675
675
Dividends paid ($
1.06
 
per share of common stock)
(1,305)
(1,305)
Repurchase of company common
 
stock
(3,000)
(3,000)
Distributions to noncontrolling
 
interests and other
(120)
(120)
Distributed under benefit plans
115
115
Other
3
3
December 31, 2017
$
18
46,622
(39,906)
(5,518)
29,391
194
30,801
Net income
6,257
48
6,305
Other comprehensive loss
(603)
(603)
Dividends paid ($
1.16
 
per share of common stock)
(1,363)
(1,363)
Repurchase of company common
 
stock
(2,999)
(2,999)
Distributions to noncontrolling
 
interests and other
(121)
(121)
Distributed under benefit plans
257
257
Changes in Accounting
 
Principles*
58
(278)
(220)
Other
3
4
7
December 31, 2018
$
18
46,879
(42,905)
(6,063)
34,010
125
32,064
Net income
7,189
68
7,257
Other comprehensive income
746
746
Dividends paid ($
1.34
 
per share of common stock)
(1,500)
(1,500)
Repurchase of company common
 
stock
(3,500)
(3,500)
Distributions to noncontrolling
 
interests and other
(128)
(128)
Distributed under benefit plans
104
104
Changes in Accounting
 
Principles**
(40)
40
-
Other
3
4
7
December 31, 2019
$
18
46,983
(46,405)
(5,357)
39,742
69
35,050
 
*Cumulative effect of the adoption
 
of ASC Topic 606,
 
"Revenue from Contracts
 
with Customers," and ASU No. 2016-01,
 
"Recognition and
 
 
Measurement
 
of Financial Assets and Liabilities," at January
 
1, 2018.
**See Note 2—Changes in Accou
 
nting Principles for additional information.
 
See Notes to Consolidated
 
Financial Statements.
 
73
 
Notes to Consolidated Financial Statements
ConocoPhillips
Note 1—Accounting Policies
■
 
 
Consolidation Principles and Investments
—Our consolidated financial statements include the
 
accounts
of majority-owned, controlled subsidiaries and
 
variable interest entities where we are the
 
primary
beneficiary.
 
The equity method is used to account for investments
 
in affiliates in which we have the
ability to exert significant influence over the affiliates’ operating
 
and financial policies.
 
When we do not
have the ability to exert significant influence, the
 
investment is measured at fair value except when the
investment does not have a readily determinable
 
fair value.
 
For those exceptions, it will be measured at
cost minus impairment, plus or minus observable
 
price changes in orderly transactions for an identical
 
or
similar investment of the same issuer.
 
Undivided interests in oil and gas joint ventures, pipelines,
 
natural
gas plants and terminals are consolidated on a proportionate
 
basis.
 
Other securities and investments are
generally carried at cost.
We
 
manage our operations through six operating
 
segments, defined by geographic region: Alaska;
 
Lower
48; Canada; Europe,
 
Middle East and North Africa;
 
Asia Pacific and Other International.
 
For additional
information, see Note 25—Segment Disclosures and Related
 
Information.
 
 
■
 
 
Foreign Currency Translation
—Adjustments resulting from the process of
 
translating foreign
functional currency financial statements into U.S.
 
dollars are included in accumulated other
comprehensive loss in common stockholders’ equity.
 
Foreign currency transaction gains and
 
losses are
included in current earnings.
 
Some of our foreign operations use their local
 
currency as the functional
currency.
■
 
 
Use of Estimates
—The preparation of financial statements
 
in conformity with accounting principles
generally accepted in the U.S. requires management to
 
make estimates and assumptions that affect
 
the
reported amounts of assets, liabilities, revenues and
 
expenses, and the disclosures of contingent assets
 
and
liabilities.
 
Actual results could differ from these estimates.
■
 
 
Revenue Recognition
—Revenues associated with the sales
 
of crude oil, bitumen, natural gas, LNG,
NGLs and other items are recognized at the point
 
in time when the customer obtains control
 
of the asset.
 
In evaluating when a customer has control of the asset,
 
we primarily consider whether the transfer of legal
title and physical delivery has occurred, whether the
 
customer has significant risks and rewards of
ownership, and whether the customer has accepted delivery
 
and a right to payment exists.
 
These products
are typically sold at prevailing market prices.
 
We allocate variable market-based consideration to
deliveries (performance obligations) in the current
 
period as that consideration relates specifically
 
to our
efforts to transfer control of current period deliveries to the
 
customer and represents the amount we
expect to be entitled to in exchange for the related products.
 
Payment is typically due within 30 days or
less.
 
Revenues associated with transactions commonly
 
called buy/sell contracts, in which the purchase and sale
of inventory with the same counterparty are entered
 
into “in contemplation” of one another, are combined
and reported net (i.e., on the same income statement
 
line).
■
 
 
Shipping and Handling Costs
—We typically incur shipping and handling costs prior to control
transferring to the customer and account for these
 
activities as fulfillment costs.
 
Accordingly, we include
shipping and handling costs in production and operating
 
expenses for production activities.
 
Transportation costs related to marketing activities are recorded in
 
purchased commodities.
 
Freight costs
billed to customers are treated as a component of
 
the transaction price and recorded as a component
 
of
revenue when the customer obtains control.
 
■
 
 
Cash Equivalents
—Cash equivalents are highly liquid, short-term
 
investments that are readily
convertible to known amounts of cash and have
 
original maturities of 90 days or less from
 
their date of
purchase.
 
They are carried at cost plus accrued interest,
 
which approximates fair value.
 
74
 
■
 
 
Short-Term
 
Investments
—Short-term investments include investments
 
in bank time deposits and
marketable securities (commercial paper and government
 
obligations) which are carried at cost plus
accrued interest and have original maturities of
 
greater than 90 days but within one year or when the
remaining maturities are within one year.
 
We also invest in financial instruments classified as available
for sale debt securities which are carried at fair value. Those
 
instruments are included in short-term
investments when they have remaining maturities
 
within one year as of the balance sheet date.
 
■
 
 
Long-Term Investments in Debt Securities
—Long-term investments in debt securities
 
includes
financial instruments classified as available for sale
 
debt securities with remaining maturities greater
 
than
one year as of the balance sheet date.
 
They are carried at fair value and presented
 
within the “Investments
and long-term receivables” line of our consolidated balance
 
sheet.
 
■
 
 
Inventories
—We have several valuation methods for our various types of inventories and consistently
use the following methods for each type of inventory.
 
The majority of our commodity-related inventories
are recorded at cost using the LIFO basis.
 
We measure these inventories at the lower-of-cost-or-market in
the aggregate.
 
Any necessary lower-of-cost-or-market write-downs
 
at year end are recorded as
permanent adjustments to the LIFO cost basis.
 
LIFO is used to better match current inventory costs
 
with
current revenues.
 
Costs include both direct and indirect expenditures
 
incurred in bringing an item or
product to its existing condition and location, but
 
not unusual/nonrecurring costs or research and
development costs.
 
Materials, supplies and other miscellaneous
 
inventories, such as tubular goods and
well equipment, are valued using various methods,
 
including the weighted-average-cost method, and the
FIFO method, consistent with industry practice.
■
 
 
Fair Value Measurements
—Assets and liabilities measured at
 
fair value and required to be categorized
within the fair value hierarchy are categorized into
 
one of three different levels depending on the
observability of the inputs employed in the measurement.
 
Level 1 inputs are quoted prices in active
markets for identical assets or liabilities.
 
Level 2 inputs are observable inputs
 
other than quoted prices
included within Level 1 for the asset or liability, either directly or indirectly
 
through market-corroborated
inputs.
 
Level 3 inputs are unobservable inputs for the asset
 
or liability reflecting significant modifications
to observable related market data or our assumptions
 
about pricing by market participants.
■
 
 
Derivative Instruments
—Derivative instruments are recorded on
 
the balance sheet at fair value.
 
If the
right of offset exists and certain other criteria are met,
 
derivative assets and liabilities with the same
counterparty are netted on the balance sheet and the
 
collateral payable or receivable is netted against
derivative assets and derivative liabilities, respectively.
Recognition and classification of the gain or loss that
 
results from recording and adjusting a derivative
 
to
fair value depends on the purpose for issuing or
 
holding the derivative.
 
Gains and losses from derivatives
not accounted for as hedges are recognized immediately
 
in earnings.
 
■
 
 
Oil and Gas Exploration and Development
—Oil and gas exploration and development
 
costs are
accounted for using the successful efforts method of accounting.
Property Acquisition Costs
—Oil and gas leasehold acquisition
 
costs are capitalized and included in
the balance sheet caption PP&E.
 
Leasehold impairment is recognized based
 
on exploratory
experience and management’s judgment.
 
Upon achievement of all conditions necessary for
 
reserves
to be classified as proved, the associated leasehold
 
costs are reclassified to proved properties.
Exploratory Costs
—Geological and geophysical costs and
 
the costs of carrying and retaining
undeveloped properties are expensed as incurred.
 
Exploratory well costs are capitalized, or
“suspended,” on the balance sheet pending further
 
evaluation of whether economically
 
recoverable
reserves have been found.
 
If economically recoverable reserves are not
 
found, exploratory well costs
are expensed as dry holes.
 
If exploratory wells encounter potentially
 
economic quantities of oil and
gas, the well costs remain capitalized on the balance sheet
 
as long as sufficient progress assessing the
reserves and the economic and operating viability
 
of the project is being made.
 
For complex
75
 
exploratory discoveries, it is not unusual to have exploratory
 
wells remain suspended on the balance
sheet for several years while we perform additional
 
appraisal drilling and seismic work on the
potential oil and gas field or while we seek government
 
or co-venturer approval of development plans
or seek environmental permitting.
 
Once all required approvals and permits have been obtained,
 
the
projects are moved into the development phase,
 
and the oil and gas resources are designated as
 
proved
reserves.
Management reviews suspended well balances quarterly, continuously monitors
 
the results of the
additional appraisal drilling and seismic work,
 
and expenses the suspended well costs
 
as dry holes
when it judges
 
the potential field does not warrant further
 
investment in the near term.
 
See Note 8—
Suspended Wells and Other Exploration Expenses, for additional information on suspended
 
wells.
Development Costs
—Costs incurred to drill and equip development
 
wells, including unsuccessful
development wells, are capitalized.
Depletion and Amortization
—Leasehold costs of producing properties are
 
depleted using the unit-
of-production method based on estimated proved oil
 
and gas reserves.
 
Amortization of intangible
development costs is based on the unit-of-production method
 
using estimated proved developed oil
and gas reserves.
■
 
 
Capitalized Interest
—Interest from external borrowings is
 
capitalized on major projects with an
expected construction period of one year or longer.
 
Capitalized interest is added to the cost of the
underlying asset and is amortized over the useful
 
lives of the assets in the same manner
 
as the underlying
assets.
■
 
 
Depreciation and Amortization
—Depreciation and amortization of PP&E
 
on producing hydrocarbon
properties and certain pipeline and LNG assets (those
 
which are expected to have a declining utilization
pattern), are determined by the unit-of-production method.
 
Depreciation and amortization of all other
PP&E are determined by either the individual-unit-straight-line
 
method or the group-straight-line method
(for those individual units that are highly integrated with
 
other units).
■
 
 
Impairment of Properties, Plants and Equipment
—PP&E used in operations are assessed for
impairment whenever changes in facts and circumstances
 
indicate a possible significant deterioration in
the future cash flows expected to be generated by an
 
asset group and annually in the fourth quarter
following updates to corporate planning assumptions.
 
If there is an indication the carrying amount of
 
an
asset may not be recovered, the asset is monitored by
 
management through an established process where
changes to significant assumptions such as prices,
 
volumes and future development plans are reviewed.
 
If, upon review, the sum of the undiscounted before-tax cash flows is less than the carrying
 
value of the
asset group, the carrying value is written down to estimated
 
fair value through additional amortization or
depreciation provisions and reported as impairments
 
in the periods in which the determination of
 
the
impairment is made.
 
Individual assets are grouped for impairment
 
purposes at the lowest level for which
there are identifiable cash flows that are largely independent
 
of the cash flows of other groups of assets—
generally on a field-by-field basis for E&P assets.
 
Because there usually is a lack of quoted
 
market prices
for long-lived assets, the fair value of impaired assets
 
is typically determined based on the present
 
values
of expected future cash flows using discount rates
 
believed to be consistent with those used by principal
market participants or based on a multiple of operating
 
cash flow validated with historical market
transactions of similar assets where possible.
 
Long-lived assets committed by management for disposal
within one year are accounted for at the lower of
 
amortized cost or fair value, less cost to sell,
 
with fair
value determined using a binding negotiated price,
 
if available, or present value of expected future
 
cash
flows as previously described.
The expected future cash flows used for impairment
 
reviews and related fair value calculations are
 
based
on estimated future production volumes, prices and costs,
 
considering all available evidence at the date of
review.
 
The impairment review includes cash flows
 
from proved developed and undeveloped reserves,
including any development expenditures necessary to
 
achieve that production.
 
Additionally, when
76
 
probable and possible reserves exist, an appropriate
 
risk-adjusted amount of these reserves may be
included in the impairment calculation.
■
 
 
Impairment of Investments in Nonconsolidated Entities
—Investments in nonconsolidated entities are
assessed for impairment whenever changes in
 
the facts and circumstances indicate a loss in value
 
has
occurred and annually following updates to corporate
 
planning assumptions.
 
When such a condition is
judgmentally determined to be other than temporary, the carrying value of
 
the investment is written down
to fair value.
 
The fair value of the impaired investment
 
is based on quoted market prices, if available, or
upon the present value of expected future cash
 
flows using discount rates believed to be consistent with
those used by principal market participants, plus market
 
analysis of comparable assets owned by the
investee, if appropriate.
■
 
 
Maintenance and Repairs
—Costs of maintenance and repairs, which are
 
not significant improvements,
are expensed when incurred.
■
 
 
Property Dispositions
—When complete units of depreciable property are
 
sold, the asset cost and related
accumulated depreciation are eliminated, with
 
any gain or loss reflected in the “Gain on
 
dispositions” line
of our consolidated income statement.
 
When less than complete units of depreciable property
 
are
disposed of or retired which do not significantly alter
 
the DD&A rate, the difference between asset cost
and salvage value is charged or credited to accumulated
 
depreciation.
■
 
 
Asset Retirement Obligations and Environmental Costs
—The
 
fair value of legal obligations to retire
and remove long-lived assets are recorded in the period
 
in which the obligation is incurred (typically
when the asset is installed at the production location).
 
When the liability is initially recorded, we
capitalize this cost by increasing the carrying amount of
 
the related PP&E.
 
If, in subsequent periods, our
estimate of this liability changes, we will record an adjustment
 
to both the liability and PP&E.
 
Over time
the liability is increased for the change in its present
 
value, and the capitalized cost in PP&E
 
is
depreciated over the useful life of the related asset.
 
Reductions to estimated liabilities for assets
 
that are
no longer producing are recorded as a credit to impairment,
 
if the asset had been previously impaired, or
as a credit to DD&A, if the asset had not been previously
 
impaired.
 
For additional information, see
Note 10—Asset Retirement Obligations and Accrued
 
Environmental Costs.
Environmental expenditures are expensed or capitalized,
 
depending upon their future economic benefit.
 
Expenditures relating to an existing condition caused
 
by past operations, and those having no future
economic benefit, are expensed.
 
Liabilities for environmental expenditures
 
are recorded on an
undiscounted basis (unless acquired in a purchase business
 
combination, which we record on a discounted
basis) when environmental assessments or cleanups
 
are probable and the costs can be reasonably
estimated.
 
Recoveries of environmental remediation costs
 
from other parties are recorded as assets when
their receipt is probable and estimable.
■
 
 
Guarantees
—The fair value of a guarantee is determined
 
and recorded as a liability at the time the
guarantee is given.
 
The initial liability is subsequently reduced
 
as we are released from exposure under
the guarantee.
 
We
 
amortize the guarantee liability over the relevant time period,
 
if one exists, based on
the facts and circumstances surrounding each type
 
of guarantee.
 
In cases where the guarantee term is
indefinite, we reverse the liability when we have
 
information indicating the liability is essentially
 
relieved
or amortize it over an appropriate time period as
 
the fair value of our guarantee exposure
 
declines over
time.
 
We amortize the guarantee liability to the related income statement line item based
 
on the nature of
the guarantee.
 
When it becomes probable that we will have to perform
 
on a guarantee, we accrue a
separate liability if it is reasonably estimable, based on
 
the facts and circumstances at that time.
 
We
reverse the fair value liability only when there is no
 
further exposure under the guarantee.
■
 
 
Share-Based Compensation
—We recognize share-based compensation expense over the shorter of the
service period (i.e., the stated period of time required
 
to earn the award) or the period beginning
 
at the
start of the service period and ending when an
 
employee first becomes eligible for retirement.
 
We have
elected to recognize expense on a straight-line basis
 
over the service period for the entire award,
 
whether
77
 
the award was granted with ratable or cliff vesting.
■
 
 
Income Taxes
—Deferred income taxes are computed
 
using the liability method and are provided
 
on all
temporary differences between the financial reporting basis
 
and the tax basis of our assets and liabilities,
except for deferred taxes on income and temporary differences
 
related to the cumulative translation
adjustment considered to be permanently reinvested in
 
certain foreign subsidiaries and foreign corporate
joint ventures.
 
Allowable tax credits are applied currently
 
as reductions of the provision for income
taxes.
 
Interest related to unrecognized tax benefits
 
is reflected in interest and debt expense, and
 
penalties
related to unrecognized tax benefits are reflected
 
in production and operating expenses.
■
 
 
Taxes Collected from Customers and Remitted to Governmental Authorities
—Sales and value-
added taxes are recorded net.
■
 
 
Net Income (Loss) Per Share of Common Stock
—Basic net income (loss) per share of common
 
stock
is calculated based upon the daily weighted-average number
 
of common shares outstanding during the
year.
 
Also, this
 
calculation includes fully vested stock and
 
unit awards that have not yet been issued as
common stock, along with an adjustment to net
 
income (loss) for dividend equivalents paid on
 
unvested
unit awards that are considered participating securities.
 
Diluted net income per share of common stock
includes unvested stock, unit or option awards granted
 
under our compensation plans and vested but
unexercised stock options, but only to the extent
 
these instruments dilute net income
 
per share, primarily
under the treasury-stock method.
 
Diluted net loss per share, which is calculated
 
the same as basic net loss
per share, does not assume conversion or exercise
 
of securities that would have an antidilutive effect.
 
Treasury stock is excluded from the daily weighted-average number of
 
common shares outstanding in
both calculations.
 
The earnings per share impact of the participating securities
 
is immaterial.
 
 
Note 2—Changes in Accounting Principles
 
 
We
adopted
 
the provisions of FASB ASU No. 2016-02, “Leases,” (ASC Topic 842) and its amendments,
beginning
January 1, 2019
.
 
ASC Topic 842 establishes comprehensive accounting and financial reporting
requirements for leasing arrangements, supersedes
 
the existing requirements in FASB ASC Topic 840,
“Leases” (ASC Topic 840), and requires lessees to recognize substantially all lease assets
 
and lease liabilities
on the balance sheet.
 
The provisions of ASC Topic 842 also modify the definition of a lease and outline
requirements for recognition, measurement, presentation
 
and disclosure of leasing arrangements by both
lessees and lessors.
 
 
We
 
adopted ASC Topic 842 using the modified retrospective approach and elected
 
to utilize the Optional
Transition Method, which permits us to apply the provisions
 
of ASC Topic 842 to leasing arrangements
existing at or entered into after January 1, 2019, and
 
present in our financial statements comparative
 
periods
prior to January 1, 2019 under the historical requirements
 
of ASC Topic 840.
 
In addition, we elected to adopt
the package of optional transition-related practical
 
expedients, which among other things, allows
 
us to carry
forward certain historical conclusions reached
 
under ASC Topic 840 regarding lease identification,
classification, and the accounting treatment of
 
initial direct costs.
 
Furthermore, we elected not to record assets
and liabilities on our consolidated balance sheet for
 
new or existing lease arrangements with
 
terms of 12
months or less.
 
The primary impact of applying ASC Topic 842 is the initial recognition of $
998
 
million of lease liabilities and
corresponding right-of-use assets
 
on our consolidated balance sheet as of January
 
1, 2019, for leases classified
as operating leases under ASC Topic 840, as well as enhanced disclosure of
 
our leasing arrangements.
 
Our
accounting treatment for finance leases remains
 
unchanged.
 
In addition, there is no cumulative effect to
retained earnings or other components of equity recognized
 
as of January 1, 2019, and the adoption of ASC
Topic 842 did not impact the presentation of our consolidated income statement or
 
statement of cash flows.
 
See Note 17—Non-Mineral Leases for additional information
 
related to the adoption of ASC Topic 842.
 
 
 
 
 
78
 
We
adopted
 
the provisions of FASB ASU No. 2018-02, “Reclassification of Certain
 
Tax Effects from
Accumulated Other Comprehensive Income,” beginning
January 1, 2019
.
 
The ASU allows a reclassification
from accumulated other comprehensive income to
 
retained earnings for stranded tax effects resulting from
 
the
Tax Cuts and Jobs Act, eliminating the stranded tax effects.
 
The cumulative effect to our consolidated balance
sheet at January 1, 2019 for the adoption of ASU No.
 
2018-02 was as follows:
 
 
 
Millions of Dollars
December 31
ASU No. 2018-02
January 1
2018
Adjustments
2019
Equity
Accumulated other comprehensive loss
$
(6,063)
(40)
(6,103)
Retained earnings
34,010
40
34,050
For additional information
 
regarding
 
the impact of the adoption of ASU
 
No. 2018-02, see Note 20—Accumulated
 
Other Comprehensive
 
Loss.
 
 
Note 3—Variable Interest Entities
 
We
 
hold variable interests in VIEs
 
for which there are existing arrangements that provide
 
those entities with
additional forms of subordinated financial support.
 
However, as we are not considered the primary
beneficiary, these entities have not been consolidated in our financial statements.
 
Marine Well Containment Company, LLC (MWCC)
 
We
 
have a
10
 
percent ownership interest in MWCC, and
 
it is accounted for as an equity method
 
investment
because MWCC is a limited liability company
 
in which we are a founding member.
 
MWCC is considered a
VIE, as it has entered into arrangements that provide
 
it with additional forms of subordinated
 
financial support.
We
 
are not the primary beneficiary and do not consolidate
 
MWCC because we share the power to govern the
business and operation of the company and to
 
undertake certain obligations that most
 
significantly impact its
economic performance with nine other unaffiliated owners
 
of MWCC.
 
 
Based on inputs related to the fair value of MWCC observed
 
in the second quarter of 2019, we reduced the
carrying value of our equity method investment
 
in MWCC to $
30
 
million and recorded a before-tax
impairment of $
95
 
million which is included in the “Equity
 
in earnings of affiliates” line on our consolidated
income statement. For additional information see Note
 
15—Fair Value Measurement.
 
At December 31, 2019,
the book value of our equity method investment
 
in MWCC was $
24
 
million. We have not provided any
financial support to MWCC other than amounts previously
 
contractually required. Unless we elect otherwise,
we have no requirement to provide liquidity or
 
purchase the assets of MWCC.
 
Australia Pacific LNG Pty Ltd (APLNG)
 
We
 
hold a
37.5
 
percent interest in APLNG, our joint venture with
 
Origin Energy and Sinopec. We are not the
primary beneficiary because we share, with our
 
joint venture partners, the power to direct the
 
key activities of
APLNG that most significantly impacts its economic
 
performance. Therefore, we do not consolidate
 
APLNG
and account for this entity as an equity method investment.
 
As of December 31, 2019, we no longer have
certain guarantees that provide APLNG with additional
 
subordinated financial support. For additional
information see Note 12—Guarantees.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
79
 
Note 4—Inventories
Inventories at December 31 were:
Millions of Dollars
2019
2018
Crude oil and natural gas
$
472
432
Materials and supplies
554
575
$
1,026
1,007
 
 
Inventories valued on the LIFO basis totaled $
286
 
million and $
292
 
million at December 31, 2019 and 2018,
respectively.
 
The estimated excess of current replacement
 
cost over LIFO cost of inventories was
approximately $
155
 
million and $
75
 
million at December 31, 2019 and December
 
31, 2018, respectively.
 
 
 
Note 5—Asset Acquisitions and Dispositions
 
All gains or losses on asset dispositions are reported before-tax
 
and are included net in the “Gain on
dispositions” line on our consolidated income statement.
 
All cash proceeds are included in the “Cash Flows
From Investing Activities” section of our consolidated
 
statement of cash flows.
 
 
 
2019
Assets Held for Sale
In October 2019, we entered into an agreement to sell
 
the subsidiaries that hold our Australia-West assets and
operations to Santos for $
1.39
 
billion, plus customary adjustments, with an effective date
 
of January 1, 2019.
 
In addition, we will receive a payment of $
75
 
million upon final investment decision
 
of the Barossa
development project.
 
These subsidiaries hold our
37.5
 
percent interest in the Barossa Project and Caldita
Field, our
56.9
 
percent interest in the Darwin LNG Facility
 
and Bayu-Undan Field, our
40
 
percent interest in
the Greater Poseidon Fields, and our
50
 
percent interest in the Athena Field.
 
The net carrying value is
approximately $
0.6
 
billion, which consisted primarily of $
1.2
 
billion of PP&E and $
0.3
 
billion of cash and
working capital, offset by $
0.7
 
billion of ARO and $
0.2
 
billion of deferred tax liabilities.
 
The assets met held
for sale criteria in the fourth quarter, and as of December 31, 2019 we had
 
reclassified $
1.2
 
billion of PP&E to
“Prepaid expenses and other current assets” and $
0.7
 
billion of noncurrent ARO to “Other accruals”
 
on our
consolidated balance sheet.
 
The before-tax earnings associated with our Australia-West subsidiaries were
$
372
 
million, $
364
 
million and $
317
 
million for the years ended December 31, 2019,
 
2018 and 2017,
respectively.
 
This transaction is expected to be completed
 
in the first quarter of 2020, subject to regulatory
approvals and other specific conditions precedent.
 
Results of operations for the subsidiaries to
 
be sold are
reported within our Asia Pacific segment.
 
In the fourth quarter of 2019, we signed an agreement
 
to sell our interests in the Niobrara shale play
 
for $
380
million, plus customary adjustments,
 
and overriding royalty interests in certain future
 
wells.
 
To reduce the
carrying value to fair value, in the fourth quarter of 2019,
 
we recorded an impairment of $
379
 
million before-
tax for developed properties and exploration expenses of
 
$
7
 
million related to leasehold impairment of
undeveloped properties.
 
Our Niobrara interests to be sold
 
have a net carrying value of approximately $
390
million, which consisted primarily of $
426
 
million of PP&E, offset by $
34
 
million of noncurrent ARO.
 
The
assets met held for sale criteria in the fourth quarter, and as of December 31, 2019,
 
we had reclassified $
426
million of PP&E to “Prepaid expenses and other current
 
assets” and $
34
 
million of noncurrent AROs to “Other
accruals” on our consolidated balance sheet.
 
The before-tax losses associated with our interests
 
in Niobrara,
including the $386 million of impairments noted above, were
 
$
372
 
million and $
12
 
million for the years ended
December 31, 2019 and 2017,
 
respectively.
 
The before-tax earnings associated with our interests
 
in Niobrara
for the year ended December 31, 2018 was $
35
 
million.
 
This transaction is subject to regulatory approval and
other specific conditions precedent and is expected
 
to close in the first quarter of 2020.
 
The Niobrara results of
 
80
 
operations are reported within our Lower 48 segment.
 
 
Assets
 
Sold
In January 2019, we entered into agreements to sell our
12.4
 
percent ownership interests in the Golden Pass
LNG Terminal and Golden Pass Pipeline.
 
We also entered into agreements to amend our contractual
obligations for retaining use of the facilities.
 
As a result of entering into these agreements, we recorded
 
a
before-tax impairment of $
60
 
million in the first quarter of 2019 which is included
 
in the “Equity in earnings
of affiliates” line on our consolidated income statement.
 
We
 
completed the sale in the second quarter of 2019.
Results of operations for these assets are reported in our
 
Lower 48 segment.
 
See Note 15—Fair Value
Measurement for additional information.
 
In April 2019, we entered into an agreement to sell
 
two ConocoPhillips U.K. subsidiaries
 
to Chrysaor E&P
Limited for $
2.675
 
billion plus interest and customary adjustments,
 
with an effective date of January 1, 2018.
 
On September 30, 2019, we completed the sale for proceeds
 
of $
2.2
 
billion and recognized a $
1.7
 
billion
before-tax and $
2.1
 
billion after-tax gain associated with this transaction in
 
2019.
 
Together the subsidiaries
sold indirectly held our exploration and production assets
 
in the U.K.
 
At the time of disposition, the net
carrying value was approximately $
0.5
 
billion, consisting primarily of $
1.6
 
billion of PP&E, $
0.5
 
billion of
cumulative foreign currency translation adjustments, and
 
$
0.3
 
billion of deferred tax assets, offset by $
1.8
billion of ARO and negative $
0.1
 
billion of working capital.
 
The before-tax earnings associated with the
subsidiaries sold were $
0.4
 
billion, $
0.9
 
billion and $
0.3
 
billion for the years ended December 31,
 
2019, 2018
and 2017, respectively.
 
Results of operations for the U.K.
 
are reported within our Europe,
 
Middle East and
North Africa segment.
 
In the second quarter of 2019, we recognized an after-tax gain of $
52
 
million upon the closing of the sale of
our
30
 
percent interest in the Greater Sunrise Fields to
 
the government of Timor-Leste for $
350
 
million.
 
The
Greater Sunrise Fields were
 
included in our Asia Pacific segment.
 
 
In the fourth quarter of 2019, we sold our interests in the
 
Magnolia field and platform for net proceeds of $
16
million and recognized a before-tax gain of $
82
 
million.
 
At the time of sale, the net carrying value consisted
of $
4
 
million of PP&E offset by $
70
 
million of ARO.
 
The Magnolia results of operations are reported within
our Lower 48 segment.
 
Planned Dispositions
In January 2020, we entered into an agreement to
 
sell our interests in certain non-core properties
 
in the Lower
48 segment for $
186
 
million, plus customary adjustments.
 
The assets met the held for sale criteria in January
2020 and the transaction is expected to be completed in
 
the first quarter of 2020.
 
No gain or loss is anticipated
on the sale.
 
This disposition will not have a significant impact
 
on Lower 48 production.
 
 
2018
Assets
 
Sold
In the first quarter of 2018, we completed the sale of
 
certain properties in the Lower 48 segment for net
proceeds of $
112
 
million.
 
No
 
gain or loss was recognized on the sale.
 
In the second quarter of 2018, we
completed the sale of a package of largely undeveloped acreage
 
in the Lower 48 segment for net proceeds
 
of
$
105
 
million and
no
 
gain or loss was recognized on the sale.
 
In the third quarter of 2018, we completed
 
a
noncash exchange of undeveloped acreage in the Lower
 
48 segment.
 
The transaction was recorded at fair
value resulting in the recognition of a $
56
 
million gain.
 
In the fourth quarter of 2018, we
 
sold several
packages of undeveloped acreage in the Lower 48 segment
 
for total net proceeds of $
162
 
million and
recognized gains of approximately $
140
 
million.
 
 
On October 31, 2018, we completed the sale of our interests
 
in the Barnett to Lime Rock Resources for $
196
million after customary adjustments and recognized
 
a loss of $
5
 
million. We recorded impairments of $
87
million in 2018 and $
572
 
million in 2017 to reduce the net carrying value
 
of the Barnett to fair value.
 
At the
time of the disposition, our interest in Barnett had a
 
net carrying value of $
201
 
million, consisting of $
250
million of PP&E and $
49
 
million of AROs.
 
The before-tax losses associated with our interests
 
in the Barnett,
 
81
 
including both the impairments and loss on disposition
 
noted above, were $
59
 
million and $
566
 
million for the
years 2018 and 2017, respectively.
 
The Barnett results of operations are
 
included in our Lower 48 segment.
 
On December 18, 2018, we completed the sale of a ConocoPhillips
 
subsidiary to BP.
 
The subsidiary held
 
16.5
 
percent of our 24 percent interest in the BP-operated
 
Clair Field in the U.K.
 
We retained a
7.5
 
percent
interest in the field.
 
At the same time, we acquired BP’s 39.2 percent nonoperated interest
 
in the Greater
Kuparuk Area in Alaska, including their 38 percent interest
 
in the Kuparuk Transportation Company (Kuparuk
Assets).
 
The transaction was recorded at a fair value of $
1,743
 
million and was cash neutral except for
customary adjustments which resulted in net proceeds
 
of $
253
 
million.
 
At closing, our interest in the Clair
Field had a net carrying value of approximately $
1,028
 
million consisting primarily of $
1,553
 
million of
PP&E, $
485
 
million of deferred tax liabilities, and $
59
 
million of AROs.
 
We recognized a before-tax gain of
$
715
 
million on the transaction.
 
The 2018 before-tax earnings associated with our
 
16.5 interest in the Clair
Field, including the recognized gain, were $
748
 
million.
 
The before-tax loss associated with our interest in the
Clair Field was $
0.4
 
million for 2017. Results of operations
 
for our interest in the Clair Field are reported
within our Europe,
 
Middle East and North Africa segment
 
and the Kuparuk Assets are included in our Alaska
segment.
 
Acquisitions
In May 2018, we completed the acquisition of Anadarko’s
22
 
percent nonoperated interest in the Western
North Slope of Alaska, as well as its interest in the Alpine
 
Transportation Pipeline for $
386
 
million, after
customary adjustments.
 
This transaction was accounted for as a
 
business combination resulting in the
recognition of approximately $
297
 
million of proved property and $
114
 
million of unproved property within
PP&E, $
20
 
million of inventory, $
14
 
million of investments, and $
59
 
million of AROs. These assets are
included in our Alaska segment.
 
As discussed in the Clair Field transaction with BP
 
above, we acquired BP’s Kuparuk Assets on December 18,
2018.
 
The transaction was accounted for as an asset acquisition
 
with a net acquisition cost of $
1,490
 
million,
comprised of the fair value of $
1,743
 
million associated with the disposed 16.5
 
percent of our 24 percent
interest in the Clair Field, reduced by the net proceeds
 
of $253 million.
 
Accordingly, we recorded
approximately $
1.9
 
billion to proved property within PP&E,
 
$
42
 
million to inventory, $
15
 
million to
investments, $
374
 
million of AROs, and a $
100
 
million decrease to net working capital.
 
The Kuparuk Assets
are included in our Alaska segment.
 
2017
Assets Sold
On May 17, 2017, we completed the sale of our 50 percent
 
nonoperated interest in the Foster Creek Christina
Lake (FCCL) Partnership, as well as the majority
 
of our western Canada gas assets to Cenovus Energy.
 
Consideration for the transaction was $
11.0
 
billion in cash after customary adjustments,
208
 
million Cenovus
Energy common shares and a five-year uncapped contingent
 
payment.
 
The value of the shares at closing was
$
1.96
 
billion based on a price of $
9.41
 
per share on the NYSE.
 
The contingent payment, calculated and paid
on a quarterly basis, is $6 million CAD for every $1 CAD by which the WCS quarterly average crude price
exceeds $52 CAD per barrel.
 
Contingent payments received during the five-year period
 
are reflected as “Gain
on dispositions” on our consolidated income statement.
 
We
 
reported before-tax equity earnings associated
with FCCL of $
197
 
million for 2017.
 
We reported a before-tax loss of $
26
 
million for the western Canada gas
producing properties for 2017.
 
We recorded gains on dispositions for these contingent payments of $
114
million and $
95
 
million for the years 2019 and 2018, respectively.
 
 
At closing, the carrying value of our equity investment
 
in FCCL was $
8.9
 
billion.
 
The carrying value of our
interest in the western Canada gas assets was $
1.9
 
billion consisting primarily of $
2.6
 
billion of PP&E, partly
offset by AROs of $
585
 
million and approximately $
100
 
million of environmental and other accruals.
 
A gain
of $
2.1
 
billion was included in the “Gain on dispositions”
 
line on our consolidated income statement in 2017.
 
Both FCCL and the western Canada gas assets were reported
 
in our Canada segment.
 
 
 
 
 
 
 
 
 
 
82
 
For more information on the Canada disposition and
 
our investment in Cenovus Energy see Note 7—
Investment in Cenovus Energy, Note 15—Fair Value
 
Measurement, and Note 20—Accumulated
 
Other
Comprehensive Loss.
 
In July 2017, we completed the sale of our interests
 
in the San Juan Basin to an affiliate of Hilcorp Energy
Company for $
2.5
 
billion in cash after customary adjustments and
 
recognized a loss on disposition of
$
22
 
million.
 
The transaction includes a contingent payment of up to $300 million. The six-year contingent
payment, effective beginning January 1, 2018, is due annually for the periods in which the monthly U.S. Henry
Hub price is at or above $3.20 per MMBTU.
 
In 2018, we recorded a gain on dispositions for
 
these contingent
payments of $
28
 
million.
 
No
 
contingent payments were recorded in 2019.
 
In the second quarter of 2017, we
recorded an impairment of $
3.3
 
billion to reduce the carrying value of our interests
 
in the San Juan Basin to
fair value.
 
At the time of disposition, the San Juan Basin interests
 
had a net carrying value of approximately
$
2.5
 
billion, consisting of $
2.9
 
billion of PP&E and $
406
 
million of liabilities, primarily AROs.
 
The before-
tax loss associated with our interests in the San Juan Basin,
 
including both the $3.3 billion impairment and $22
million loss on disposition noted above, was $
3.2
 
billion for 2017.
 
The San Juan Basin results were reported
in our Lower 48 segment.
 
 
In September 2017, we completed the sale of our interest
 
in the Panhandle assets for $
178
 
million in cash after
customary adjustments and recognized a loss on disposition
 
of $
28
 
million.
 
At the time of the disposition, the
carrying value of our interest was $
206
 
million, consisting primarily of $
279
 
million of PP&E and $
72
 
million
of AROs.
 
Including the $28 million loss on disposition
 
noted above, we reported a before-tax loss
 
for the
Panhandle properties of $
14
 
million for 2017.
 
The Panhandle results were reported in our
 
Lower 48 segment.
 
 
 
Note 6—Investments, Loans and Long-Term Receivables
Components of investments, loans and long-term receivables
 
at December 31 were:
Millions of Dollars
2019
2018
Equity investments
$
8,234
9,005
Loans and advances—related parties
219
335
Long-term receivables
243
238
Long-term investments in debt securities
133
-
Other investments
77
86
$
8,906
9,664
 
 
Equity Investments
 
Affiliated companies in which we had a significant equity
 
investment at December 31, 2019, included:
 
 
●
 
 
APLNG—
37.5
 
percent owned joint venture with Origin
 
Energy (
37.5
 
percent) and Sinopec
(
25
 
percent)—to produce CBM from the Bowen
 
and Surat basins in Queensland, Australia, as
 
well as
process and export LNG.
●
 
 
Qatar Liquefied Gas Company Limited (3) (QG3)—30
 
percent owned joint venture with affiliates of
Qatar Petroleum (
68.5
 
percent) and Mitsui & Co., Ltd. (
1.5
 
percent)—produces and liquefies natural
gas from Qatar’s North Field, as well as exports LNG.
 
 
 
 
 
 
 
 
 
 
 
83
 
Summarized 100 percent earnings information for equity
 
method investments in affiliated companies,
 
combined, was as follows:
Millions of Dollars
2019
2018
2017
Revenues
$
11,310
11,654
11,554
Income (loss) before income taxes
3,726
3,660
(2,875)
Net income (loss)
3,085
3,244
(1,431)
 
 
Summarized 100 percent balance sheet information
 
for equity method investments in affiliated companies,
 
combined, was as follows:
Millions of Dollars
2019
2018
Current assets
$
3,289
3,285
Noncurrent assets
38,905
41,563
Current liabilities
2,603
2,625
Noncurrent liabilities
22,168
23,874
 
Our share of income taxes incurred directly by an
 
equity method investee is reported in equity
 
in earnings of
affiliates, and as such is not included in income taxes
 
on our consolidated financial statements.
 
At December 31, 2019, retained earnings included $
32
 
million related to the undistributed earnings of
affiliated companies.
 
Dividends received from affiliates were $
1,378
 
million, $
1,226
 
million and $
605
 
million
in 2019, 2018 and 2017,
 
respectively.
 
 
APLNG
 
APLNG is focused on CBM production from the
 
Bowen and Surat basins in Queensland, Australia,
 
to supply
the domestic gas market and on LNG processing
 
and export sales.
 
Our investment in APLNG gives us access
to CBM resources in Australia and enhances our LNG
 
position.
 
The majority of APLNG LNG is sold under
two long-term sales and purchase agreements, supplemented
 
with sales of additional LNG spot cargoes
targeting the Asia Pacific markets.
 
Origin Energy, an integrated Australian energy company, is the operator of
APLNG’s production and pipeline system, while we operate the LNG facility.
 
APLNG executed project financing agreements for an
 
$
8.5
 
billion project finance facility in 2012.
 
The $8.5
billion project finance facility was initially composed
 
of financing agreements executed by APLNG
 
with the
Export-Import Bank of the United States for approximately
 
$
2.9
 
billion, the Export-Import Bank of China for
approximately $
2.7
 
billion, and a syndicate of Australian and
 
international commercial banks for
approximately $
2.9
 
billion.
 
At December 31, 2019, all amounts
 
have been drawn from the facility.
 
APLNG
made its first principal and interest repayment in March
 
2017 and is scheduled to make
bi-annual
 
payments
until March 2029.
 
APLNG made a voluntary repayment of $
1.4
 
billion to the Export-Import Bank of China
 
in September 2018.
 
At the same time, APLNG obtained a United States Private
 
Placement (USPP) bond facility of $
1.4
 
billion.
 
APLNG made its first interest payment related to
 
this facility in March 2019, and principal payments
 
are
scheduled to commence in September 2023, with
bi-annual
 
payments due on the facility until September
 
2030.
 
During the first quarter of 2019, APLNG
 
refinanced $
3.2
 
billion of existing project finance debt through two
transactions.
 
As a result of the first transaction, APLNG obtained
 
a commercial bank facility of $
2.6
 
billion.
 
APLNG made its first principal and interest repayment
 
in September 2019 with
bi-annual
 
payments due on the
facility until March 2028.
 
Through the second transaction, APLNG
 
obtained a USPP bond facility of $
0.6
billion.
 
APLNG made its first interest payment in September 2019,
 
and principal payments are scheduled
 
to
84
 
commence in September 2023, with
bi-annual
 
payments due on the facility until September
 
2030.
 
In conjunction with the $3.2 billion debt obtained
 
during the first quarter of 2019 to refinance existing
 
project
finance debt, APLNG made voluntary repayments
 
of $
2.2
 
billion and $
1.0
 
billion to a syndicate of Australian
and international commercial banks and the Export-Import
 
Bank of China, respectively.
 
At December 31, 2019, a balance of $
6.7
 
billion was outstanding on the facilities.
 
See Note 12—Guarantees,
for additional information.
 
During the first half of 2017, the outlook for crude
 
oil prices deteriorated, and as a result of
 
significantly
reduced price outlooks, the estimated fair value of our
 
investment in APLNG declined to an amount
 
below
carrying value.
 
Based on a review of the facts and circumstances
 
surrounding this decline in fair value, we
concluded in the second quarter of 2017 the impairment
 
was other than temporary under the guidance of
 
FASB
ASC Topic 323, “Investments—Equity Method and Joint Ventures,” and the recognition of an impairment of
our investment to fair value was necessary.
 
Accordingly, we recorded a noncash $
2,384
 
million, before- and
after-tax impairment in our second quarter 2017 results.
 
Fair value was estimated based on an internal
discounted cash flow model using estimated future
 
production, an outlook of future prices from a combination
of exchanges (short-term) and pricing service companies
 
(long-term), costs, a market outlook of foreign
exchange rates provided by a third party, and a discount rate believed to be consistent
 
with those used by
principal market participants.
 
The impairment was included in the “Impairments”
 
line on our consolidated
income statement.
 
At December 31, 2019, the carrying value of our equity
 
method investment in APLNG was $
7,228
 
million.
 
The historical cost basis of our
37.5
 
percent share of net assets on the books of APLNG
 
was $
6,751
 
million,
resulting in a basis difference of $
477
 
million on our books.
 
The basis difference, which is substantially all
associated with PP&E and subject to amortization, has
 
been allocated on a relative fair value basis to
individual exploration and production license areas
 
owned by APLNG, some of which are not currently
 
in
production.
 
Any future additional payments are expected
 
to be allocated in a similar manner.
 
Each
exploration license area will periodically be reviewed for any
 
indicators of potential impairment, which,
 
if
required, would result in acceleration of basis difference
 
amortization.
 
As the joint venture produces natural
gas from each license, we amortize the basis difference
 
allocated to that license using the unit-of-production
method.
 
Included in net income (loss) attributable
 
to ConocoPhillips for 2019,
 
2018 and 2017 was after-tax
expense of $
36
 
million, $
44
 
million and $
100
 
million, respectively, representing the amortization of this basis
difference on currently producing licenses.
 
Distributions from APLNG commenced in April
 
2018.
 
FCCL
FCCL Partnership, a Canadian upstream 50/50 general
 
partnership with Cenovus Energy Inc., produces
bitumen in the Athabasca oil sands in northeastern
 
Alberta and sells the bitumen blend.
 
Cenovus is the
operator and managing partner of FCCL.
 
 
On May 17, 2017, we completed the sale of our
 
50 percent nonoperated interest in the FCCL
 
Partnership, as
well as the majority of our western Canada gas assets
 
to Cenovus Energy.
 
Financial information presented
within this footnote includes our historical interest
 
up to the date of sale.
 
For additional information on the
Canada disposition and our investment in Cenovus
 
Energy, see Note 5—Asset Acquisitions and Dispositions
and Note 7—Investment in Cenovus Energy.
 
QG3
QG3 is a joint venture that owns an integrated large-scale LNG
 
project located in Qatar.
 
We provided project
financing, with a current outstanding balance of $
335
 
million as described below under “Loans and
 
Long-
Term Receivables.”
 
At December 31, 2019, the book value of our equity
 
method investment in QG3,
excluding the project financing, was $
797
 
million.
 
We have terminal and pipeline use agreements with Golden
Pass LNG Terminal and affiliated Golden Pass Pipeline near Sabine Pass, Texas, intended to provide us with
terminal and pipeline capacity for the receipt,
 
storage and regasification of LNG purchased
 
from QG3.
 
We
85
 
previously held a 12.4 percent interest in Golden Pass
 
LNG Terminal and Golden Pass Pipeline, but we sold
those interests in the second quarter of 2019 while
 
retaining the basic use agreements.
 
Currently, the LNG
from QG3 is being sold to markets outside of the
 
U.S.
 
For additional information, see Note 5—Asset
Acquisitions and Dispositions.
 
Loans and Long-Term Receivables
As part of our normal ongoing business operations and
 
consistent with industry practice, we enter into
numerous agreements with other parties to pursue
 
business opportunities.
 
Included in such activity are loans
and long-term receivables to certain affiliated and non-affiliated companies.
 
Loans are recorded when cash is
transferred or seller financing is provided to the affiliated or
 
non-affiliated company pursuant to a loan
agreement.
 
The loan balance will increase as interest
 
is earned on the outstanding loan
 
balance and will
decrease as interest and principal payments are received.
 
Interest is earned at the loan agreement’s stated
interest rate.
 
Loans and long-term receivables are assessed
 
for impairment when events indicate the loan
balance may not be fully recovered.
 
 
At December 31, 2019,
 
significant loans to affiliated companies include
 
$335 million in project financing to
QG3.
 
We own a
30
 
percent interest in QG3, for which we
 
use the equity method of accounting.
 
The other
participants in the project are affiliates of Qatar Petroleum
 
and Mitsui.
 
QG3 secured project financing of
$
4.0
 
billion in December 2005, consisting of $
1.3
 
billion of loans from export credit agencies
 
(ECA), $
1.5
billion from commercial banks, and $
1.2
 
billion from ConocoPhillips.
 
The ConocoPhillips loan facilities have
substantially the same terms as the ECA and commercial
 
bank facilities.
 
On December 15, 2011, QG3
achieved financial completion and all project loan
 
facilities became nonrecourse to the project participants.
 
Semi-annual
 
repayments began in January 2011 and will extend through
 
July 2022.
 
The long-term portion of these
 
loans is included in the “Loans and
 
advances—related parties” line on our
consolidated balance sheet, while the short-term portion
 
is in “Accounts and notes receivable—related
 
parties.”
 
 
Note 7—Investment in Cenovus Energy
 
On May 17, 2017, we completed the sale of our
50
 
percent nonoperated interest in the FCCL
 
Partnership, as
well as the majority of our western Canada gas assets,
 
to Cenovus Energy.
 
Consideration for the transaction
included
208
 
million Cenovus Energy common shares, which, at closing,
 
approximated
16.9
 
percent of issued
and outstanding Cenovus Energy common stock.
 
See Note 5—Asset Acquisitions and Dispositions,
 
for
additional information on the Canada disposition.
 
The fair value and cost basis of our investment
 
in 208
million Cenovus Energy common shares was $
1.96
 
billion based on a price of $
9.41
 
per share on the NYSE on
the closing date.
 
 
Our investment on our consolidated balance sheet
 
as of December 31, 2019, is carried at fair value
 
of $
2.11
billion, reflecting the closing price of Cenovus Energy
 
shares on the NYSE of $
10.15
 
per share, an increase of
$
649
 
million from $
1.46
 
billion at December 31, 2018.
 
The increase in fair value represents the
 
net unrealized
gain recorded within the “Other income” line of our
 
consolidated income statement for the year ended
December 31, 2019 relating to the shares held at
 
the reporting date.
 
See Note 15—Fair Value Measurement
and Note 22—Other Financial Information,
 
for additional information.
 
Subject to market conditions, we
intend to decrease our investment over time through
 
market transactions, private agreements or
 
otherwise.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
86
 
Note 8—Suspended Wells and Other Exploration Expenses
The following table reflects the net changes in suspended
 
exploratory well costs during 2019, 2018 and 2017:
Millions of Dollars
2019
2018
2017
Beginning balance at January 1
$
856
853
1,063
Additions pending the determination of proved reserves
239
140
118
Reclassifications to proved properties
(11)
(37)
(66)
Sales of suspended wells
(54)
(93)
-
Charged to dry hole expense
(10)
(7)
(262)
Ending balance at December 31
 
$
1,020
*
856
853
*Includes $
313
 
million of assets held for sale in Australia.
 
 
The following table provides an aging of suspended
 
well balances at December 31:
Millions of Dollars
2019
2018
2017
Exploratory well costs capitalized for a period of
 
one year or less
$
206
145
67
Exploratory well costs capitalized for a period greater
 
than one year
814
711
786
Ending balance
$
1,020
*
856
853
Number of projects with exploratory well costs capitalized
 
for a
period greater than one year
23
24
23
*Includes $
313
 
million of assets held for sale in Australia.
 
 
The following table provides a further aging of
 
those exploratory well costs that have been
 
capitalized for more
than one year since the completion of drilling
 
as of December 31, 2019:
Millions of Dollars
Suspended Since
Total
2016–2018
2013–2015
2004–2012
Greater Poseidon—Australia
(2)(3)
177
-
157
20
NPRA—Alaska
(1)
149
111
38
-
Barossa/Caldita—Australia
(2)(3)
136
59
-
77
Surmont—Canada
(1)
118
6
55
57
Middle Magdalena Basin—Colombia
(1)
68
-
68
-
Narwhal Trend—Alaska
(1)
52
52
-
-
Kamunsu East—Malaysia
(2)
19
-
19
-
NC 98—Libya
(2)
15
-
11
4
WL4-00—Malaysia
(2)
17
17
-
-
Other of $10 million or less each
(1)(2)
63
20
26
17
Total
$
814
265
374
175
(1)Additional appraisal wells planned.
(2)Appraisal drilling complete;
 
costs being incurred
 
to assess development.
(3)Assets held for sale as of December
 
31, 2019.
 
 
 
 
 
 
 
 
 
 
87
 
Other Exploration Expenses
In February 2017, we reached a settlement agreement
 
on our contract for the Athena drilling rig, initially
secured for our four-well commitment program in Angola.
 
As a result of the cancellation, we recognized a
before-tax charge of $
43
 
million net in the first quarter of 2017.
 
These charges are included in the
“Exploration expenses” line on our consolidated income
 
statement and in our Other International segment
 
in
2017.
 
In 2019, we recorded before-tax dry hole expenses of
 
$
111
 
million due to our decision to discontinue
exploration activities in the Central Louisiana
 
Austin Chalk trend.
 
These charges are included in our Lower 48
segment and in the “Exploration expenses” line on
 
our consolidated income statement.
 
See Note 9—
Impairments for additional information on our decision
 
to discontinue these exploration activities.
 
 
Note 9—Impairments
During 2019, 2018 and 2017, we recognized the
 
following before-tax impairment charges:
Millions of Dollars
2019
2018
2017
Alaska
$
-
20
180
Lower 48
402
63
3,969
Canada
2
9
22
Europe, Middle East and North Africa
1
(79)
46
Asia Pacific
-
14
2,384
$
405
27
6,601
 
 
2019
 
In the Lower 48, we recorded impairments of $
402
 
million, primarily related to developed
 
properties in our
Niobrara asset which were written down to fair value
 
less costs to sell.
 
See Note 5—Asset Acquisitions and
Dispositions, for additional information on this disposition.
 
 
The charges discussed below, within this section, are included in the “Exploration expenses”
 
line on our
consolidated income statement and are not reflected
 
in the table above.
 
 
In our Lower 48 segment, we recorded a before-tax impairment
 
of $
141
 
million for the associated carrying
value of capitalized undeveloped leasehold costs due
 
to our decision to discontinue exploration activities
related to our Central Louisiana Austin Chalk acreage.
 
 
2018
 
In Alaska, we recorded impairments of $
20
 
million primarily due to cancelled projects.
 
 
 
In the Lower 48, we recorded impairments of $
63
 
million, primarily related to developed
 
properties in our
Barnett asset which were written down to fair value less
 
costs to sell, partly offset by a revision to reflect
finalized proceeds on a separate transaction.
 
 
 
In our Europe, Middle East and North Africa segment, we
 
recorded a credit to impairment of $
79
 
million,
primarily due to decreased ARO estimates on fields in the
 
U.K. which have ceased production and were
impaired in prior years, partly offset by an increased ARO
 
estimate on a field in Norway which has ceased
production.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
88
 
2017
 
In Alaska, we recorded impairments of $
180
 
million primarily for the associated PP&E
 
carrying value of our
small interest in the Point Thomson unit.
 
 
 
In the Lower 48, we recorded impairments of $
3,969
 
million primarily due to certain developed
 
properties
which were written down to fair value less costs to sell.
 
See Note 5—Asset Acquisitions and Dispositions,
 
for
additional information on our dispositions.
 
 
In Canada, we recorded impairments of $
22
 
million primarily due to cancelled projects.
 
 
In Europe, Middle East and North Africa, we recorded impairments
 
of $
46
 
million primarily due to reduced
volume forecasts for a field in the U.K. and restructured
 
ownership and a change in commercial premises
 
for a
gas processing plant in Norway, partly offset by decreased ARO estimates on fields at or
 
nearing the end of
life which were impaired in prior years.
 
 
In Asia Pacific, we recorded impairments of $
2,384
 
million, including the impairment of
 
our APLNG
investment.
 
For more information, see the “APLNG”
 
section of Note 6—Investments, Loans and
 
Long-Term
Receivables.
 
 
 
The charges discussed below, within this section, are included in the “Exploration
 
expenses” line on our
consolidated income statement and are not reflected
 
in the table above.
 
 
In our Lower 48 segment, we recorded a before-tax impairment
 
of $
51
 
million for the associated carrying
value of capitalized undeveloped leasehold costs of Shenandoah
 
in deepwater Gulf of Mexico following the
suspension of appraisal activity by the operator.
 
Additionally, we recorded a $
38
 
million before-tax
impairment for mineral assets primarily due to plan of
 
development changes.
 
 
 
Note 10—Asset Retirement Obligations and Accrued
 
Environmental Costs
 
Asset retirement obligations and accrued environmental
 
costs at December 31 were:
Millions of Dollars
2019
2018
Asset retirement obligations
$
6,206
7,908
Accrued environmental costs
171
178
Total asset retirement obligations and accrued environmental costs
6,377
8,086
Asset retirement obligations and accrued environmental
 
costs due within one year*
(1,025)
(398)
Long-term asset retirement obligations and accrued
 
environmental costs
$
5,352
7,688
*Classified as a current
 
liability on the balance sheet
 
under “Other accruals.” $
741
 
million relates to assets which
 
are held for sale as
 
of
December 31, 2019. For additional
 
information see Note 5—Asset Acquisitions
 
and Dispositions.
 
 
Asset Retirement Obligations
We
 
record the fair value of a liability for an ARO when it
 
is incurred (typically when the asset is installed at
the production location).
 
When the liability is initially recorded, we capitalize
 
the associated asset retirement
cost by increasing the carrying amount of the related PP&E.
 
If, in subsequent periods, our estimate of this
liability changes, we will record an adjustment
 
to both the liability and PP&E.
 
Over time, the liability
increases for the change in its present value, while the
 
capitalized cost depreciates over the useful life of the
related asset.
 
 
 
 
 
 
 
 
 
 
 
89
 
We
 
have numerous AROs we are required to
 
perform under law or contract once an
 
asset is permanently taken
out of service.
 
Most of these obligations are not expected
 
to be paid until several years, or decades, in the
future and will be funded from general company resources
 
at the time of removal.
 
Our largest individual
obligations involve plugging and abandonment of
 
wells and removal and disposal of offshore oil and gas
platforms around the world, as well as oil and gas production
 
facilities and pipelines in Alaska.
 
During 2019 and 2018, our overall ARO changed
 
as follows:
Millions of Dollars
2019
2018
Balance at January 1
$
7,908
7,798
Accretion of discount
322
348
New obligations
155
657
Changes in estimates of existing obligations
50
(266)
Spending on existing obligations
(229)
(228)
Property dispositions
(1,920)
(161)
Foreign currency translation
(80)
(240)
Balance at December 31
$
6,206
7,908
 
 
Accrued Environmental Costs
Total accrued environmental costs at December 31, 2019 and 2018, were $
171
 
million and $
178
 
million,
respectively.
 
 
We
 
had accrued environmental costs of $
112
 
million and $
100
 
million at December 31, 2019 and 2018,
respectively, related to remediation activities in the U.S.
 
and Canada.
 
We had also accrued in Corporate and
Other $
47
 
million and $
67
 
million of environmental costs associated with
 
sites no longer in operation at
December 31, 2019 and 2018, respectively.
 
In addition, $
12
 
million and $
11
 
million were included at both
December 31, 2019 and 2018, respectively, where the company has been named
 
a potentially responsible party
under the Federal Comprehensive Environmental
 
Response, Compensation and Liability Act, or similar
 
state
laws.
 
Accrued environmental liabilities are expected
 
to be paid over periods extending up to
30
 
years.
 
Expected expenditures for environmental obligations
 
acquired in various business combinations are discounted
using a weighted-average
5
 
percent discount factor, resulting in an accrued balance
 
for acquired environmental
liabilities of $
97
 
million at December 31, 2019.
 
The expected future undiscounted payments related
 
to the
portion of the accrued environmental costs that
 
have been discounted are: $
10
 
million in 2020, $
7
 
million in
2021, $
10
 
million in 2022, $
3
 
million in 2023, $
2
 
million in 2024, and $
108
 
million for all future years
after 2024.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
90
 
Note 11—Debt
Long-term debt at December 31 was:
Millions of Dollars
2019
2018
9.125% Debentures due 2021
$
123
123
8.20% Debentures due 2025
134
134
8.125% Notes due 2030
390
390
7.9% Debentures due 2047
60
60
7.8% Debentures due 2027
203
203
7.65% Debentures due 2023
78
78
7.40% Notes due 2031
500
500
7.375% Debentures due 2029
92
92
7.25% Notes due 2031
500
500
7.20% Notes due 2031
575
575
7% Debentures due 2029
200
200
6.95% Notes due 2029
1,549
1,549
6.875% Debentures due 2026
67
67
6.50% Notes due 2039
2,750
2,750
5.951% Notes due 2037
645
645
5.95% Notes due 2036
500
500
5.95% Notes due 2046
500
500
5.90% Notes due 2032
505
505
5.90% Notes due 2038
600
600
4.95% Notes due 2026
1,250
1,250
4.30% Notes due 2044
750
750
4.15% Notes due 2034
246
246
3.35% Notes due 2024
426
426
3.35% Notes due 2025
199
199
2.4% Notes due 2022
329
329
Floating rate notes due 2022 at
2.81
% –
3.58
% during 2019 and
2.32
% –
3.52
% during 2018
500
500
Industrial Development Bonds due 2035 at
1.08
% –
2.45
% during 2019 and
0.95
% –
1.86
% during 2018
18
18
Marine Terminal Revenue Refunding Bonds due 2031 at
1.08
% –
2.45
% during
 
2019 and
0.88
% –
1.95
% during 2018
265
265
Other
17
17
Debt at face value
13,971
13,971
Finance leases
720
777
Net unamortized premiums, discounts and debt issuance
 
costs
204
220
Total debt
14,895
14,968
Short-term debt
(105)
(112)
Long-term debt
$
14,790
14,856
91
 
Maturities of long-term borrowings, inclusive of net
 
unamortized premiums and discounts,
 
in 2020 through
2024 are: $
105
 
million, $
235
 
million, $
940
 
million, $
198
 
million and $
548
 
million, respectively.
 
 
We
 
have a revolving credit facility totaling $
6.0
 
billion with an expiration date of May 2023.
 
Our revolving
credit facility may be used for direct bank borrowings,
 
the issuance of letters of credit totaling up
 
to $
500
million, or as support for our commercial paper program.
 
The revolving credit facility is broadly syndicated
among financial institutions and does not contain
 
any material adverse change provisions or any covenants
requiring maintenance of specified financial ratios
 
or credit ratings.
 
The facility agreement contains a cross-
default provision relating to the failure to pay principal
 
or interest on other debt obligations of
 
$
200
 
million or
more by ConocoPhillips, or any of its consolidated
 
subsidiaries.
 
Credit facility borrowings may bear interest at a
 
margin above rates offered by certain designated banks in the
London interbank market or at a margin above the overnight
 
federal funds rate or prime rates offered by
certain designated banks in the U.S.
 
The agreement calls for commitment fees
 
on available, but unused,
amounts.
 
The agreement also contains early termination
 
rights if our current directors or their approved
successors cease to be a majority of the Board
 
of Directors.
 
We
 
have a $
6.0
 
billion commercial paper program, which is
 
primarily a funding source for short-term working
capital needs.
 
Commercial paper maturities are generally
 
limited to
90 days
.
 
We had no commercial paper
outstanding in programs in place at December 31, 2019 or
December 31, 2018
.
 
We had
no
 
direct outstanding
borrowings or letters of credit under the revolving credit
 
facility at December 31, 2019 or
December 31, 2018
.
 
Since we had
no
 
commercial paper outstanding and had issued no letters
 
of credit, we had access to
$
6.0
 
billion in borrowing capacity under our revolving
 
credit facility at December 31, 2019
.
 
 
At both December 31, 2019 and
2018
, we had $
283
 
million of certain variable rate demand
 
bonds (VRDBs)
outstanding which mature
 
in 2035.
 
The VRDBs are redeemable at the option
 
of the bondholders on any
business day.
 
If they are ever redeemed, we intend to refinance
 
on a long-term basis, therefore,
 
the VRDBs are
included in the “Long-term debt” line on our consolidated
 
balance sheet.
 
 
For additional information on Finance Leases, see Note 17
—
Non-Mineral Leases.
 
 
 
Note 12—Guarantees
 
 
At December 31, 2019, we were liable for certain contingent
 
obligations under various contractual
arrangements as described below.
 
We
 
recognize a liability, at inception, for the fair value of our obligation as
a guarantor for newly issued or modified guarantees.
 
Unless the carrying amount of the liability is
 
noted
below, we have not recognized a liability because the fair value of the obligation is
 
immaterial.
 
In addition,
unless otherwise stated, we are not currently performing
 
with any significance under the guarantee and expect
future performance to be either immaterial or have
 
only a remote chance of occurrence.
 
 
APLNG Guarantees
 
At December 31, 2019, we had outstanding multiple
 
guarantees in connection with our
37.5
 
percent ownership
interest in APLNG.
 
The following is a description of the guarantees with
 
values calculated utilizing
 
December
2019 exchange rates:
 
 
●
 
During the third quarter of 2016, we issued a guarantee
 
to facilitate the withdrawal of our pro-rata
portion of the funds in a project finance reserve account.
 
We
 
estimate the remaining term of this
guarantee is
11 years
.
 
Our maximum exposure under this guarantee is approximately
 
$
170
 
million
and may become payable if an enforcement action
 
is commenced by the project finance lenders
against APLNG.
 
At December 31, 2019, the carrying value
 
of this guarantee is approximately $
14
million.
 
92
 
●
 
In conjunction with our original purchase of an ownership
 
interest in APLNG from Origin Energy in
October 2008, we agreed to reimburse Origin Energy for our
 
share of the existing contingent liability
arising under guarantees of an existing obligation of
 
APLNG to deliver natural gas under several
 
sales
agreements with remaining terms of up to
22 years
.
 
Our maximum potential liability for future
payments, or cost of volume delivery, under these guarantees is estimated to be $
780
 
million ($
1.4
billion in the event of intentional or reckless breach)
 
and would become payable if APLNG fails to
meet its obligations under these agreements and the
 
obligations cannot otherwise be mitigated.
 
Future
payments are considered unlikely, as the payments, or cost of volume delivery, would only be
triggered if APLNG does not have enough natural gas
 
to meet these sales commitments and if the
 
co-
venturers do not make necessary equity contributions
 
into APLNG.
 
●
 
We
 
have guaranteed the performance of APLNG
 
with regard to certain other contracts executed in
connection with the project’s continued development.
 
The guarantees have remaining terms of up
 
to
26 years or the life of the venture
.
 
As of December 31, 2019, we were released from certain of
 
these
guarantees considered subordinated financial support
 
to APLNG.
 
Our remaining maximum potential
amount of future payments related to the remaining
 
guarantees is approximately $
60
 
million and
would become payable if APLNG does not perform.
 
Other Guarantees
 
We
 
have other guarantees with maximum
 
future potential payment amounts totaling
 
approximately
$
820
 
million, which consist primarily of guarantees
 
of the residual value of leased office buildings, guarantees
of the residual value of leased corporate aircraft, and
 
a guarantee for our portion of a joint venture’s project
finance reserve accounts.
 
These guarantees have remaining terms of up to
three years
 
and would become
payable if, upon sale, certain asset values are lower
 
than guaranteed amounts, business conditions
 
decline at
guaranteed entities, or as a result of nonperformance
 
of contractual terms by guaranteed parties.
 
 
 
In conjunction with the disposition of our two U.K.
 
subsidiaries to Chrysaor E&P Limited, we will
 
temporarily
continue to support various guarantees and letters
 
of credit which were provided for the benefit
 
of entities that
are now affiliates of Chrysaor E&P Limited.
 
Our maximum potential payment exposure under
 
these
obligations is approximately $
100
 
million.
 
Chrysaor E&P Limited has agreed to fully
 
indemnify
ConocoPhillips for any losses suffered by us related to these
 
obligations.
 
 
 
Indemnifications
 
Over the years, we have entered into agreements to
 
sell ownership interests in certain corporations,
 
joint
ventures and assets that gave rise to qualifying indemnifications.
 
These agreements include indemnifications
for taxes, environmental liabilities, employee claims
 
and litigation.
 
The terms of these indemnifications vary
greatly.
 
The majority of these indemnifications
 
are related to environmental issues, the term
 
is generally
indefinite and the maximum amount of future payments
 
is generally unlimited.
 
The carrying amount recorded
for these indemnifications at December 31, 2019, was approximately
 
$
80
 
million.
 
We
 
amortize the
indemnification liability over the relevant time
 
period, if one exists, based on the facts and circumstances
surrounding each type of indemnity.
 
In cases where the indemnification term is
 
indefinite, we will reverse the
liability when we have information the liability is
 
essentially relieved or amortize the liability
 
over an
appropriate time period as the fair value of our indemnification
 
exposure declines.
 
Although it is reasonably
possible future payments may exceed amounts recorded,
 
due to the nature of the indemnifications,
 
it is not
possible to make a reasonable estimate of the maximum
 
potential amount of future payments.
 
Included in the
recorded carrying amount at December 31, 2019, were approximately
 
$
30
 
million of environmental accruals
for known contamination that are included in the “Asset
 
retirement obligations and accrued environmental
costs” line on our consolidated balance sheet.
 
For additional information about environmental
 
liabilities, see
Note 13—Contingencies and Commitments.
 
 
93
 
Note 13—Contingencies and Commitments
 
 
A number of lawsuits involving a variety of claims
 
arising in the ordinary course of business have been
 
filed
against ConocoPhillips.
 
We also may be required to remove or mitigate the effects on the environment of
 
the
placement, storage, disposal or release of certain chemical,
 
mineral and petroleum substances at various active
and inactive sites.
 
We
 
regularly assess the need for accounting
 
recognition or disclosure of these
contingencies.
 
In the case of all known contingencies (other
 
than those related to income taxes), we accrue
 
a
liability when the loss is probable and the amount is
 
reasonably estimable.
 
If a range of amounts can be
reasonably estimated and no amount within the range
 
is a better estimate than any other amount,
 
then the
minimum of the range is accrued.
 
We do not reduce these liabilities for potential insurance or third-party
recoveries.
 
If applicable, we accrue receivables for
 
probable insurance or other third-party recoveries.
 
With
respect to income tax-related contingencies, we use a
 
cumulative probability-weighted loss accrual in cases
where sustaining a tax position is less than certain.
 
See Note 19—Income Taxes, for additional information
about income tax-related contingencies.
 
Based on currently available information, we
 
believe it is remote that future costs related to known
 
contingent
liability exposures will exceed current accruals by an
 
amount that would have a material adverse
 
impact on our
consolidated financial statements.
 
As we learn new facts concerning contingencies, we
 
reassess our position
both with respect to accrued liabilities and other potential
 
exposures.
 
Estimates particularly sensitive to future
changes include contingent liabilities recorded for environmental
 
remediation, tax and legal matters.
 
Estimated future environmental remediation costs are
 
subject to change due to such factors as
 
the uncertain
magnitude of cleanup costs, the unknown time and
 
extent of such remedial actions that may be
 
required, and
the determination of our liability in proportion
 
to that of other responsible parties.
 
Estimated future costs
related to tax and legal matters are subject to change
 
as events evolve and as additional information becomes
available during the administrative and litigation
 
processes.
 
Environmental
We
 
are subject to international, federal, state and local
 
environmental laws and regulations.
 
When we prepare
our consolidated financial statements, we record
 
accruals for environmental liabilities based on
 
management’s
best estimates, using all information that is available
 
at the time.
 
We
 
measure estimates and base liabilities
 
on
currently available facts, existing technology, and presently enacted laws
 
and regulations, taking into account
stakeholder and business considerations.
 
When measuring environmental liabilities,
 
we also consider our prior
experience in remediation of contaminated sites, other
 
companies’ cleanup experience, and data released by
the U.S. EPA or other organizations.
 
We consider unasserted claims in our determination of environmental
liabilities, and we accrue them in the period they
 
are both probable and reasonably estimable.
 
Although liability of those potentially responsible
 
for environmental remediation costs
 
is generally joint and
several for federal sites and frequently so for other
 
sites, we are usually only one of many companies
 
cited at a
particular site.
 
Due to the joint and several liabilities, we could
 
be responsible for all cleanup costs related
 
to
any site at which we have been designated as a potentially
 
responsible party.
 
We have been successful to date
in sharing cleanup costs with other financially
 
sound companies.
 
Many of the sites at which we are potentially
responsible are still under investigation by the EPA or the agency concerned.
 
Prior to actual cleanup, those
potentially responsible normally assess the site conditions,
 
apportion responsibility and determine the
appropriate remediation.
 
In some instances, we may have
 
no liability or may attain a settlement of liability.
 
Where it appears that other potentially responsible parties
 
may be financially unable to bear their proportional
share, we consider this inability in estimating our
 
potential liability, and we adjust our accruals accordingly.
 
As a result of various acquisitions in the past, we assumed
 
certain environmental obligations.
 
Some of these
environmental obligations are mitigated by indemnifications
 
made by others for our benefit, and some of the
indemnifications are subject to dollar limits and time
 
limits.
 
 
We
 
are currently participating in environmental
 
assessments and cleanups at numerous federal
 
Superfund and
comparable state and international sites.
 
After an assessment of environmental exposures
 
for cleanup and
other costs, we make accruals on an undiscounted basis
 
(except those acquired in a purchase business
combination, which we record on a discounted
 
basis) for planned investigation and remediation
 
activities for
94
 
sites where it is probable future costs will be incurred and
 
these costs can be reasonably estimated.
 
We
 
have
not reduced these accruals for possible insurance recoveries.
 
In the future, we may be involved in additional
environmental assessments, cleanups and proceedings.
 
See Note 10—Asset Retirement Obligations and
Accrued Environmental Costs, for a summary of
 
our accrued environmental liabilities.
 
Legal Proceedings
We
 
are subject to various lawsuits and claims including
 
but not limited to matters involving oil and
 
gas royalty
and severance tax payments, gas measurement and valuation
 
methods, contract disputes, environmental
damages, climate change, personal injury, and property damage.
 
Our primary exposures for such matters
relate to alleged royalty and tax underpayments on
 
certain federal, state and privately owned
 
properties and
claims of alleged environmental contamination
 
from historic operations.
 
We
 
will continue to defend ourselves
vigorously in these matters.
 
Our legal organization applies its knowledge, experience and
 
professional judgment to the specific
characteristics of our cases, employing a litigation
 
management process to manage and monitor
 
the legal
proceedings against us.
 
Our process facilitates the early evaluation and quantification
 
of potential exposures in
individual cases.
 
This process also enables us to track those cases that
 
have been scheduled for trial and/or
mediation.
 
Based on professional judgment and
 
experience in using these litigation management
 
tools and
available information about current developments
 
in all our cases, our legal organization regularly assesses
 
the
adequacy of current accruals and determines if adjustment
 
of existing accruals, or establishment of new
accruals, is required.
 
Other Contingencies
We
 
have contingent liabilities resulting
 
from throughput agreements with pipeline and
 
processing companies
not associated with financing arrangements.
 
Under these agreements, we may be required to provide
 
any such
company with additional funds through advances
 
and penalties for fees related to throughput
 
capacity not
utilized.
 
In addition, at December 31, 2019, we had performance
 
obligations secured by letters of credit
 
of
$
277
 
million (issued as direct bank letters of credit) related
 
to various purchase commitments for materials,
supplies, commercial activities and services incident
 
to the ordinary conduct of business.
 
In 2007, ConocoPhillips was unable to reach agreement with
 
respect to the empresa mixta structure mandated
by the Venezuelan government’s
 
Nationalization Decree.
 
As a result, Venezuela’s
 
national oil company,
Petróleos de Venezuela, S.A. (PDVSA), or its affiliates, directly assumed control over ConocoPhillips’
interests in the Petrozuata and Hamaca heavy oil ventures and
 
the offshore Corocoro development project.
 
In
response to this expropriation, ConocoPhillips initiated international
 
arbitration on November 2, 2007, with the
ICSID.
 
On September 3, 2013, an ICSID arbitration tribunal held that
 
Venezuela
 
unlawfully expropriated
ConocoPhillips’ significant oil investments in June 2007.
 
On January 17, 2017, the Tribunal reconfirmed the
decision that the expropriation was unlawful.
 
In March 2019, the Tribunal unanimously ordered the
government of Venezuela to pay ConocoPhillips approximately $
8.7
 
billion in compensation for the
government’s unlawful expropriation of the company’s investments in Venezuela in 2007.
 
ConocoPhillips has
filed a request for recognition of the award in several
 
jurisdictions.
 
On August 29, 2019, the ICSID Tribunal
issued a decision rectifying the award and reducing it by
 
approximately $
227
 
million.
 
The award now stands
at $
8.5
 
billion plus interest.
 
The government of Venezuela sought annulment of the award.
 
 
In 2014, ConocoPhillips filed a separate and independent
 
arbitration under the rules of the ICC against
PDVSA under the contracts that had established the
 
Petrozuata and Hamaca projects.
 
The ICC Tribunal issued
an award in April 2018, finding that PDVSA owed
 
ConocoPhillips approximately $
2
 
billion
under their
agreements in connection with the expropriation of the projects and other pre-expropriation fiscal measures. In
August 2018, ConocoPhillips entered into a settlement with PDVSA to recover the full amount of this ICC
award, plus interest through the payment period, including initial payments totaling approximately $500
million within a period of 90 days from the time of signing of the settlement agreement. The balance of the
settlement is to be paid quarterly over a period of four and a half years.
 
To date, ConocoPhillips has received
approximately $
754
 
million.
 
Per the settlement, PDVSA recognized the ICC
 
award as a judgment in various
jurisdictions, and ConocoPhillips agreed to suspend
 
its legal enforcement actions.
 
ConocoPhillips sent notices
95
 
of default to PDVSA on October 14 and November 12, 2019,
 
and to date PDVSA failed to cure its breach.
 
As
a result, ConocoPhillips has resumed legal enforcement
 
actions.
 
ConocoPhillips has ensured that the
settlement and any actions thereof meet all appropriate
 
U.S. regulatory requirements, including those related
 
to
any applicable sanctions imposed by the U.S. against
 
Venezuela
 
.
 
In 2016, ConocoPhillips filed a separate and independent
 
arbitration under the rules of the ICC against
PDVSA under the contracts that had established the
 
Corocoro project.
 
On August 2, 2019, the ICC
 
Tribunal
awarded ConocoPhillips approximately $
55
 
million under the Corocoro contracts.
 
ConocoPhillips is seeking
recognition and enforcement of the award in various jurisdictions.
 
ConocoPhillips has ensured that all the
actions related to the award meet all appropriate U.S.
 
regulatory requirements, including those related to any
applicable sanctions imposed by the U.S. against Venezuela.
 
In February 2017, the ICSID Tribunal unanimously awarded
 
Burlington Resources, Inc., a wholly owned
subsidiary of ConocoPhillips, $
380
 
million for Ecuador’s unlawful expropriation of Burlington’s investment
 
in
Blocks 7 and 21, in breach of the U.S.-Ecuador Bilateral
 
Investment Treaty.
 
The tribunal also issued a
separate decision finding Ecuador to be entitled to $
42
 
million for environmental and infrastructure
counterclaims.
 
In December 2017, Burlington and Ecuador
 
entered into a settlement agreement by which
Ecuador paid Burlington $
337
 
million in two installments.
 
The first installment of $
75
 
million was paid in
December 2017, and the second installment of $
262
 
million was paid in April 2018.
 
The settlement included
an offset for the counterclaims decision, of which Burlington
 
is entitled to a contribution from Perenco
Ecuador Limited, its co-venturer and consortium operator,
 
pursuant to a joint and several liability provision
 
in
the JOA.
 
In September 2019, a separate ICSID Tribunal issued an award
 
in the Perenco arbitration, ordering
Perenco to pay an additional $
54
 
million to Ecuador for its environmental
 
counterclaim.
 
Burlington and
Perenco will reconcile their shares of the environmental
 
and infrastructure counterclaims according to their
JOA participating interests, and we expect Burlington’s share will be immaterial.
 
In June 2017, FAR Ltd. initiated arbitration before the ICC against ConocoPhillips
 
Senegal B.V.
 
in connection
with the sale of ConocoPhillips Senegal B.V. to Woodside Energy
 
Holdings (Senegal) Limited in 2016.
 
In
February 2020, the ICC Tribunal issued an award dismissing FAR Ltd.’s claims
 
in the arbitration.
 
In late 2017, ConocoPhillips (U.K.) Limited (CPUKL)
 
initiated United Nations Commission
 
on International
Trade and Law (UNCITRAL) arbitration against Vietnam in accordance with the U.K.-Vietnam Bilateral
Investment Treaty relating to a tax dispute arising from the 2012 sale of
 
ConocoPhillips (U.K.) Cuu Long
Limited and ConocoPhillips (U.K.) Gama Limited.
 
The parties entered into a settlement agreement
 
in October
2019, and the arbitration was dismissed in December
 
2019 as a result of this agreement.
 
In 2017 and 2018, cities, counties, and a state government
 
in California, New York, Washington,
 
Rhode Island
and Maryland, as well as the Pacific Coast Federation
 
of Fishermen’s Association, Inc., have filed lawsuits
against oil and gas companies, including ConocoPhillips,
 
seeking compensatory damages and equitable relief
to abate alleged climate change impacts.
 
ConocoPhillips is vigorously defending against
 
these lawsuits.
 
The
lawsuits brought by the Cities of San Francisco,
 
Oakland and New York have been dismissed by the district
courts and appeals are pending.
 
Lawsuits filed by other cities and counties
 
in California and Washington are
currently stayed pending resolution of the appeals
 
brought by the Cities of San Francisco and Oakland
 
to the
U.S. Court of Appeals for the Ninth Circuit.
 
Lawsuits filed in Maryland and Rhode
 
Island are proceeding in
state court while rulings in those matters, on the
 
issue of whether the matters should proceed
 
in state or federal
court, are on appeal to the U.S. Court of Appeals for
 
the Fourth Circuit and First Circuit, respectively.
 
Several Louisiana parishes and individual landowners
 
have filed lawsuits against oil and gas
 
companies,
including ConocoPhillips, seeking compensatory damages
 
in connection with historical oil and gas operations
in Louisiana.
 
All parish lawsuits are stayed pending an
 
appeal to the Fifth Circuit Court of Appeals on
 
the
issue of whether they will proceed in federal or state
 
court.
 
ConocoPhillips will vigorously defend against
these lawsuits.
 
 
 
 
 
 
 
 
 
 
 
 
 
96
 
 
Long-Term Throughput Agreements and Take
 
-or-Pay Agreements
We
 
have certain throughput agreements
 
and take-or-pay agreements in support of financing
 
arrangements.
 
The agreements typically provide for natural gas
 
or crude oil transportation to be used in the ordinary course
 
of
the company’s business.
 
The aggregate amounts of estimated payments
 
under these various agreements are:
2020—$
7
 
million; 2021—$
7
 
million; 2022—$
7
 
million; 2023—$
7
 
million; 2024—$
7
 
million; and 2025 and
after—$
57
 
million.
 
Total payments under the agreements were $
25
 
million in 2019, $
39
 
million in 2018 and
$
43
 
million in 2017.
 
 
Note 14—Derivative and Financial Instruments
 
We
 
use futures, forwards, swaps and options
 
in various markets to meet our customer needs
 
and capture
market opportunities.
 
Our commodity business primarily consists
 
of natural gas, crude oil, bitumen, LNG
 
and
NGLs.
 
 
Our derivative instruments are held at fair value
 
on our consolidated balance sheet.
 
Where these balances have
the right of setoff, they are presented on a net basis.
 
Related cash flows are recorded as operating
 
activities on
our consolidated statement of cash flows.
 
On our consolidated income statement, realized and
 
unrealized gains
and losses are recognized either on a gross basis if directly
 
related to our physical business or a net basis
 
if held
for trading.
 
Gains and losses related to contracts that
 
meet and are designated with the NPNS
 
exception are
recognized upon settlement.
 
We generally apply this exception to eligible crude contracts.
 
We do not use
hedge accounting for our commodity derivatives.
 
The following table presents the gross fair values
 
of our commodity derivatives, excluding
 
collateral, and the
line items where they appear on our consolidated balance
 
sheet:
Millions of Dollars
2019
2018
Assets
Prepaid expenses and other current assets
$
288
410
Other assets
34
40
Liabilities
Other accruals
283
370
Other liabilities and deferred credits
28
30
 
 
The gains (losses) from commodity derivatives incurred,
 
and the line items where they appear on our
consolidated income statement were:
Millions of Dollars
2019
2018
2017
Sales and other operating revenues
$
141
45
77
Other income
4
7
-
Purchased commodities
(118)
(41)
(61)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
97
 
The table below summarizes our material net exposures
 
resulting from outstanding commodity
 
derivative
contracts:
Open Position
Long/(Short)
2019
2018
Commodity
Natural gas and power (billions of cubic feet equivalent)
Fixed price
(5)
(17)
Basis
(23)
(1)
 
 
Foreign Currency Exchange Derivatives
We
 
have foreign currency exchange rate risk
 
resulting from international operations.
 
Our foreign currency
exchange derivative activity primarily relates to managing
 
our cash-related foreign currency exchange rate
exposures, such as firm commitments for capital programs
 
or local currency tax payments, dividends and cash
returns from net investments in foreign affiliates,
 
and investments in equity securities.
 
We do not elect hedge
accounting on our foreign currency exchange derivatives.
 
The following table presents the gross fair values of our
 
foreign currency exchange derivatives, excluding
collateral, and the line items where they appear on our
 
consolidated balance sheet:
Millions of Dollars
2019
2018
Assets
Prepaid expenses and other current assets
$
1
7
Liabilities
Other accruals
20
6
Other liabilities and deferred credits
8
-
 
 
The losses from foreign currency exchange derivatives
 
incurred and the line item where they
 
appear on our
consolidated income statement were:
Millions of Dollars
2019
2018
2017
Foreign currency transaction losses
$
16
1
13
 
We
 
had the following net notional position of
 
outstanding foreign currency exchange
 
derivatives:
In Millions
Notional Currency
2019
2018
Foreign Currency Exchange Derivatives
Sell U.S. dollar, buy British pound
USD
-
805
Sell British pound, buy other currencies*
GBP
-
21
Buy British pound, sell euro
GBP
4
-
Sell Canadian dollar, buy U.S. dollar
CAD
1,337
1,242
*Primarily euro and
 
Norwegian krone.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
98
 
In December 2017, we entered into foreign exchange zero cost collars buying the right to sell $1.25 billion
CAD at $0.707 CAD and selling the right to buy $1.25 billion CAD at $0.842 CAD against the U.S. dollar.
The collar expired during the second quarter of 2019 and we entered into new foreign currency exchange
forward contracts to sell $1.35 billion CAD at $0.748 CAD against the U.S. dollar.
 
 
 
 
Financial Instruments
We
 
invest in financial instruments with maturities
 
based on our cash forecasts for the various accounts
 
and
currency pools we manage.
 
The types of financial instruments in which we currently
 
invest include:
 
●
 
Time deposits: Interest bearing deposits placed with financial institutions.
●
 
Demand deposits:
 
Interest bearing deposits placed with financial institutions.
 
Deposited funds can be
withdrawn without notice.
●
 
Commercial paper: Unsecured promissory notes
 
issued by a corporation, commercial bank or
government agency purchased at a discount to mature
 
at par.
 
●
 
U.S. government or government agency obligations:
 
Securities issued by the U.S. government or U.S.
government agencies.
●
 
Corporate bonds:
 
Unsecured debt securities issued by corporations.
●
 
Asset-backed securities: Collateralized debt securities.
 
 
The following investments are carried on our
 
consolidated balance sheet at cost, plus accrued interest:
 
 
 
 
Carrying Amount
Cash and Cash Equivalents
Short-Term Investments
2019
2018
2019
2018
Cash
$
759
876
Demand Deposits
1,483
-
-
-
Time Deposits
Remaining maturities from 1 to 90 days
2,030
3,509
1,395
-
Remaining maturities from 91 to 180 days
-
-
465
-
Commercial Paper
Remaining maturities from 1 to 90 days
413
229
1,069
248
U.S. Government Obligations
Remaining maturities from 1 to 90 days
394
1,301
-
-
$
5,079
5,915
2,929
248
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
99
 
The following table reflects our investments in debt
 
securities classified as available for sale
 
at December 31,
2019 which are carried at fair value:
Millions of Dollars
Carrying Amount
Cash and
Cash
Equivalents
Short-Term
Investments
Investments
and Long-
Term
Receivables
Corporate Bonds
Remaining maturities within one year
$
1
59
-
Remaining maturities greater than one year through five
 
years
-
-
99
Commercial Paper
Remaining maturities within one year
8
30
-
U.S. Government Obligations
Remaining maturities within one year
-
10
-
Remaining maturities greater than one year through five
 
years
-
-
15
Asset-backed Securities
Remaining maturities greater than one year through five
 
years
-
-
19
$
9
99
133
 
The following table summarizes the amortized cost
 
basis and fair value of investments in debt securities
classified as available for sale at December 31, 2019:
Millions of Dollars
Amortized Cost
Basis
Fair Value
Major Security Type
Corporate bonds
$
159
159
Commercial paper
38
38
U.S. government obligations
25
25
Asset-backed securities
19
19
$
241
241
 
Gross unrealized gains and gross unrealized losses
 
included in other comprehensive income related
 
to
investments in debt securities classified as available for
 
sale as of December 31, 2019, were negligible.
 
There were no other-than-temporary impairments
 
recognized in earnings or in other comprehensive
 
income
during the year ended December 31, 2019.
 
Gross realized gains and gross realized losses included
 
in earnings from sales and redemptions
 
of investments
in debt securities classified as available for sale during the
 
year ended December 31, 2019,
 
were negligible.
 
The cost of securities sold and redeemed is determined
 
using the specific identification method.
100
 
Credit Risk
Financial instruments potentially exposed to concentrations
 
of credit risk consist primarily of cash equivalents,
short-term investments, long-term investments in
 
debt securities, OTC derivative contracts
 
and trade
receivables.
 
Our cash equivalents and short-term investments
 
are placed in high-quality commercial paper,
government money market funds, government debt
 
securities,
 
time deposits with major international banks
 
and
financial institutions,
 
and high-quality corporate bonds.
 
Our long-term investments in debt securities are
placed in high-quality corporate bonds, U.S. government
 
obligations, and asset-backed securities.
 
 
The credit risk from our OTC derivative contracts,
 
such as forwards, swaps and options, derives
 
from the
counterparty to the transaction.
 
Individual counterparty exposure is
 
managed within predetermined credit
limits and includes the use of cash-call margins when appropriate,
 
thereby reducing the risk of significant
nonperformance.
 
We also use futures, swaps and option contracts that have a negligible credit
 
risk because
these trades are cleared primarily
 
with an exchange clearinghouse and subject to mandatory
 
margin
requirements until settled; however, we are exposed to the
 
credit risk of those exchange brokers for receivables
arising from daily margin cash calls, as well as for cash
 
deposited to meet initial margin requirements.
 
 
Our trade receivables result primarily from our petroleum
 
operations and reflect a broad national and
international customer base, which limits our exposure
 
to concentrations of credit risk.
 
The majority of these
receivables have payment terms of 30 days or less, and
 
we continually monitor this exposure and the
creditworthiness of the counterparties.
 
We do not generally require collateral to limit the exposure to loss;
however, we will sometimes use letters of credit, prepayments and
 
master netting arrangements to mitigate
credit risk with counterparties that both buy from
 
and sell to us, as these agreements permit
 
the amounts owed
by us or owed to others to be offset against amounts due
 
to us.
 
Certain of our derivative instruments contain provisions that require us to post collateral if the derivative
exposure exceeds a threshold amount. We have contracts with fixed threshold amounts and other contracts
with variable threshold amounts that are contingent on our credit rating. The variable threshold amounts
typically decline for lower credit ratings, while both the variable and fixed threshold amounts typically revert
to zero if we fall below investment grade. Cash is the primary collateral in all contracts; however, many also
permit us to post letters of credit as collateral, such as transactions administered through the New York
Mercantile Exchange.
 
The aggregate fair value of all derivative instruments
 
with such credit risk-related contingent features that
 
were
in a liability position on December 31, 2019 and December
 
31, 2018, was $
79
 
million and $
62
 
million,
respectively.
 
For these instruments,
no
 
collateral was posted as of December 31, 2019 or
December 31, 2018
.
 
If our credit rating had been downgraded below
 
investment grade on December 31, 2019,
 
we would be
required to post $
76
 
million of additional collateral, either
 
with cash or letters of credit.
 
Note 15—Fair Value Measurement
 
We
 
carry a portion of our assets and liabilities at fair value
 
that are measured at a reporting date using
 
an exit
price (i.e., the price that would be received to sell
 
an asset or paid to transfer a liability) and disclosed
according to the quality of valuation inputs under the
 
following hierarchy:
 
●
 
Level 1: Quoted prices (unadjusted) in an active market
 
for identical assets or liabilities.
●
 
Level 2: Inputs other than quoted prices that are directly
 
or indirectly observable.
●
 
Level 3: Unobservable inputs that are significant to the
 
fair value of assets or liabilities.
 
The classification of an asset or liability is based
 
on the lowest level of input significant to
 
its fair value.
 
Those
that are initially classified as Level 3 are subsequently
 
reported as Level 2 when the fair value derived from
unobservable inputs is inconsequential to the overall
 
fair value, or if corroborated market data becomes
available.
 
Assets and liabilities initially reported as Level
 
2 are subsequently reported as Level 3 if
corroborated market data is no longer available.
 
Transfers occur at the end of the reporting period.
 
There were
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
101
 
no material transfers in or out of Level 1 during
 
2019 or 2018.
 
 
Recurring Fair Value Measurement
Financial assets and liabilities reported at fair value
 
on a recurring basis primarily include our investment
 
in
Cenovus Energy shares, our investments
 
in debt securities classified as available
 
for sale, and commodity
derivatives.
 
 
●
 
Level 1 derivative assets and liabilities primarily represent
 
exchange-traded futures and options that are
valued using unadjusted prices available from the
 
underlying exchange.
 
Level 1 also includes our
investment in common shares of Cenovus Energy, which is valued using quotes for shares on
 
the NYSE,
and our investments in U.S. government obligations
 
classified as available for sale debt securities,
 
which
are valued using exchange prices.
 
●
 
Level 2 derivative assets and liabilities primarily represent
 
OTC swaps, options and forward purchase and
sale contracts that are valued using adjusted exchange prices,
 
prices provided by brokers or pricing service
companies that are all corroborated by market data.
 
Level 2 also includes our investments
 
in debt
securities classified as available for sale including
 
investments in corporate bonds, commercial paper, and
asset-backed securities that are valued using pricing
 
provided by brokers or pricing service companies
 
that
are corroborated with market data.
 
●
 
Level 3 derivative assets and liabilities consist
 
of OTC swaps, options and forward purchase and sale
contracts where a significant portion of fair value is calculated
 
from underlying market data that is not
readily available.
 
The derived value uses industry standard
 
methodologies that may consider the historical
relationships among various commodities, modeled market
 
prices, time value, volatility factors and other
relevant economic measures.
 
The use of these inputs results
 
in management’s best estimate of fair value.
 
Level 3 activity was not material for all periods presented.
 
The following table summarizes the fair value hierarchy
 
for gross financial assets and liabilities (i.e.,
unadjusted where the right of setoff exists for commodity derivatives
 
accounted for at fair value on a recurring
basis):
 
Millions of Dollars
December 31, 2019
December 31, 2018
Level 1
Level 2
Level 3
Total
Level 1
Level 2
Level 3
Total
Assets
Investment in Cenovus Energy
$
2,111
-
-
2,111
1,462
-
-
1,462
Investments in debt securities
25
216
-
241
Commodity derivatives
172
114
36
322
236
181
33
450
Total assets
$
2,308
330
36
2,674
1,698
181
33
1,912
Liabilities
Commodity derivatives
$
174
115
22
311
225
145
30
400
Total liabilities
$
174
115
22
311
225
145
30
400
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
102
 
The following table summarizes those commodity
 
derivative balances subject to the right of setoff as
presented on our consolidated balance sheet.
 
We have elected to offset the recognized fair value amounts for
multiple derivative instruments executed with the same
 
counterparty in our financial statements when
 
a legal
right of setoff exists.
Millions of Dollars
Amounts Subject to Right of Setoff
Gross
Amounts Not
Gross
Net
Amounts
Subject to
Gross
Amounts
Amounts
Cash
Net
Recognized
Right of Setoff
Amounts
Offset
Presented
Collateral
Amounts
December 31, 2019
Assets
$
322
3
319
193
126
4
122
Liabilities
311
4
307
193
114
12
102
December 31, 2018
Assets
$
450
9
441
280
161
-
161
Liabilities
400
4
396
280
116
10
106
At December 31, 2019 and December 31, 2018, we
 
did not present any amounts gross on our consolidated
balance sheet where we had the right of setoff.
 
Non-Recurring Fair Value Measurement
The following table summarizes the fair value
 
hierarchy by major category and date of remeasurement
 
for
assets accounted for at fair value on a non-recurring
 
basis:
Millions of Dollars
Fair Value
 
Measurements Using
Fair Value
Level 1
Inputs
Level 2
Inputs
Level 3
Inputs
Before-Tax
Loss
Year
 
ended December 31, 2019
Net PP&E (held for sale)
 
November 30, 2019
$
194
194
-
-
351
 
December 31, 2019
166
166
-
-
28
Equity Method Investments
 
March 31, 2019
171
171
-
-
60
 
May 31, 2019
30
-
30
-
95
Year
 
ended December 31, 2018
Net PP&E (held for sale)
 
March 31, 2018
$
250
-
-
250
44
 
September 30, 2018
201
201
-
-
43
 
Net PP&E (held for sale)
Net PP&E held for sale was written down to fair value,
 
less costs to sell.
 
The fair value of each asset was
 
determined by its negotiated selling price (Level 1)
 
or information gathered during marketing efforts (Level
 
3).
 
For additional information see Note 5—Asset Acquisitions
 
and Dispositions.
 
 
Equity Method Investments
During 2019, certain equity method investments
 
were determined to have fair values below their
 
carrying
amounts, and the impairments were considered to
 
be other than temporary under the guidance of FASB ASC
 
 
 
 
 
 
 
 
 
 
 
 
103
 
Topic 323.
 
During 2019, investments using Level 1 inputs
 
were written down to fair value, less costs to sell,
determined by negotiated selling prices.
 
For additional information, see Note 5—Asset Acquisitions
 
and
Dispositions.
 
During 2019, an investment using Level 2 inputs
 
was determined to have a fair value below its
carrying value, and was written down to fair value.
 
For additional information, see Note 3—Variable Interest
Entities.
 
 
Reported Fair Values of Financial Instruments
We
 
used the following methods and assumptions
 
to estimate the fair value of financial
 
instruments:
 
●
 
Cash and cash equivalents and short-term investments:
 
The carrying amount reported on the balance
sheet approximates fair value.
 
For those investments classified
 
as available for sale debt securities,
the carrying amount reported on the balance sheet
 
is fair value.
●
 
Accounts and notes receivable (including long-term
 
and related parties): The carrying amount
reported on the balance sheet approximates fair value.
 
The valuation technique and methods
 
used to
estimate the fair value of the current portion of fixed-rate related
 
party loans is consistent with Loans
and advances—related parties.
●
 
Investment in Cenovus Energy shares: See Note 7—Investment
 
in Cenovus Energy for a discussion of
the carrying value and fair value of our investment in Cenovus
 
Energy shares.
 
●
 
Investments in debt securities classified as available for
 
sale:
 
The fair value of investments in debt
securities categorized as Level 1 in the fair value hierarchy
 
is measured using exchange prices.
 
The
fair value of investments in debt securities categorized
 
as Level 2 in the fair value hierarchy is
measured using pricing provided by brokers or pricing service
 
companies that are corroborated
 
with
market data.
 
See Note 14—Derivatives and Financial Instruments, for
 
additional information.
 
●
 
Loans and advances—related parties: The carrying
 
amount of floating-rate loans approximates
 
fair
value.
 
The fair value of fixed-rate loan activity is measured
 
using market observable data and is
categorized as Level 2 in the fair value hierarchy.
 
See Note 6—Investments, Loans and Long-Term
Receivables, for additional information.
●
 
Accounts payable (including related parties) and floating-rate
 
debt: The carrying amount of accounts
payable and floating-rate debt reported on the balance sheet
 
approximates fair value.
 
●
 
Fixed-rate debt: The estimated fair value of fixed-rate
 
debt is measured using prices available from
 
a
pricing service that is corroborated by market data; therefore,
 
these liabilities are categorized as
 
Level
2 in the fair value hierarchy.
 
The following table summarizes the net fair value of
 
financial instruments (i.e., adjusted where the
 
right of
setoff exists for commodity derivatives):
Millions of Dollars
Carrying Amount
Fair Value
2019
2018
2019
2018
Financial assets
Investment in Cenovus Energy
$
2,111
1,462
2,111
1,462
Commodity derivatives
125
170
125
170
Investments in debt securities
241
-
241
-
Total loans and advances—related parties
339
468
339
468
Financial liabilities
Total debt, excluding finance leases
14,175
14,191
18,108
16,147
Commodity derivatives
106
110
106
110
 
 
Commodity Derivatives
At December 31, 2019, commodity derivative assets
 
and liabilities are presented net with $
4
 
million in
obligations to return cash collateral and $
12
 
million of rights to reclaim cash collateral,
 
respectively.
 
At
December 31, 2018, commodity derivative assets and
 
liabilities are presented net with
no
 
obligations to return
cash collateral and $
10
 
million of rights to reclaim cash collateral,
 
respectively.
 
 
 
 
 
 
 
 
 
 
 
 
104
 
Note 16—Equity
Common Stock
The changes in our shares of common stock, as categorized
 
in the equity section of the balance sheet, were:
Shares
2019
2018
2017
Issued
Beginning of year
1,791,637,434
1,785,419,175
1,782,079,107
Distributed under benefit plans
4,014,769
6,218,259
3,340,068
End of year
1,795,652,203
1,791,637,434
1,785,419,175
Held in Treasury
Beginning of year
653,288,213
608,312,034
544,809,771
Repurchase of common stock
57,495,601
44,976,179
63,502,263
End of year
710,783,814
653,288,213
608,312,034
 
 
Preferred Stock
 
We
 
have authorized
500
 
million shares of preferred stock, par value
 
$
0.01
 
per share,
none
 
of which was issued
or outstanding at December 31, 2019 or 2018.
 
Noncontrolling Interests
 
At December 31, 2019 and 2018, we had $
69
 
million and $
125
 
million outstanding, respectively, of equity in
less-than-wholly owned consolidated subsidiaries held
 
by noncontrolling interest owners.
 
For both periods,
the amounts were related to the Darwin LNG
 
and Bayu-Darwin Pipeline operating joint ventures
 
we control.
 
Repurchase of Common Stock
As of December 31, 2019, we had announced a total authorization
 
to repurchase $
15
 
billion of our common
stock.
 
Repurchase of shares began in November 2016,
 
and totaled
168,553,141
 
shares at a cost of $
9,625
million, through December 31, 2019.
 
In February 2020, we announced
 
that the Board of Directors approved
an increase to our repurchase authorization from $15
 
billion to $
25
 
billion, to support our plan for future share
repurchases.
 
 
 
Note 17—Non-Mineral Leases
 
 
The company primarily leases office buildings and drilling
 
equipment, as well as ocean transport vessels,
tugboats, corporate aircraft, and other facilities and equipment.
 
Certain leases include escalation clauses for
adjusting rental payments to reflect changes in price
 
indices and other leases include payment provisions
 
that
vary based on the nature of usage of the leased
 
asset.
 
Additionally, the company has executed certain leases
that provide it with the option to extend or renew the
 
term of the lease, terminate the lease prior to the
 
end of
the lease term, or purchase the leased asset as
 
of the end of the lease term.
 
In other cases, the company has
executed lease agreements that require it to guarantee
 
the residual value of certain leased office buildings.
 
For
additional information about guarantees, see Note
 
12—Guarantees.
 
There are no significant restrictions
imposed on us by the lease agreements with regard to dividends,
 
asset dispositions or borrowing ability.
 
105
 
Certain arrangements may contain both lease and
 
non-lease components and we determine if an arrangement
 
is
or contains a lease at contract inception.
 
Only the lease components of these contractual
 
arrangements are
subject to the provisions of ASC Topic 842, and any non-lease components are subject to other
 
applicable
accounting guidance; however, we have
elected
 
to adopt the optional
practical expedient
 
not to separate lease
components apart from non-lease components for
 
accounting purposes. This policy election has
 
been adopted
for each of the company’s leased asset classes existing as of the effective date
 
and subject to the transition
provisions of ASC Topic 842 and will be applied to all new or modified leases
 
executed on or after January 1,
2019.
 
For contractual arrangements executed in subsequent
 
periods involving a new leased asset class, the
company will determine at contract inception whether
 
it will apply the optional practical expedient to
 
the new
leased asset class.
 
 
Leases are evaluated for classification as operating
 
or finance leases at the commencement date of
 
the lease
and right-of-use assets and corresponding liabilities
 
are recognized on our consolidated balance sheet
 
based on
the present value of future lease payments relating to
 
the use of the underlying asset during the lease term.
 
Future lease payments include variable lease payments
 
that depend upon an index or rate using the index or
rate at the commencement date and probable amounts
 
owed under residual value guarantees.
 
The amount of
future lease payments may be increased to include additional
 
payments related to lease extension, termination,
and/or purchase options when the company has
 
determined, at or subsequent to lease commencement,
generally due to limited asset availability or operating
 
commitments, it is reasonably certain of exercising
 
such
options.
 
We use our incremental borrowing rate as the discount rate in determining the present
 
value of future
lease payments, unless the interest rate implicit
 
in the lease arrangement is readily determinable.
 
Lease
payments that vary subsequent to the commencement
 
date based on future usage levels, the nature of
 
leased
asset activities, or certain other contingencies are not
 
included in the measurement of lease right-of-use assets
and corresponding liabilities.
 
We
 
have elected not to record assets and liabilities
 
on our consolidated balance
sheet for lease arrangements with terms of 12 months
 
or less.
 
 
We
 
often enter into leasing arrangements
 
acting in the capacity as operator for and/or on
 
behalf of certain oil
and gas joint ventures of undivided interests.
 
If the lease arrangement can be legally enforced only
 
against us
as operator and there is no separate arrangement to sublease
 
the underlying leased asset to our coventurers, we
recognize at lease commencement a right-of-use
 
asset and corresponding lease liability on our
 
consolidated
balance sheet on a gross basis.
 
While we record lease costs on a gross basis in our
 
consolidated income
statement and statement of cash flows, such costs are
 
offset by the reimbursement we receive from our
coventurers for their share of the lease cost as the underlying
 
leased asset is utilized in joint venture activities.
 
As a result, lease cost is presented in our consolidated income
 
statement and statement of cash flows on
 
a
proportional basis.
 
If we are a nonoperating coventurer, we recognize a right-of-use asset
 
and corresponding
lease liability only if we were a specified contractual
 
party to the lease arrangement and the arrangement
 
could
be legally enforced against us.
 
In this circumstance, we would
 
recognize both the right-of-use asset and
corresponding lease liability on our consolidated
 
balance sheet on a proportional basis consistent with
 
our
undivided interest ownership in the related joint venture.
 
 
The company has historically recorded certain finance
 
leases executed by investee companies accounted
 
for
under the proportionate consolidation method of accounting
 
on its consolidated balance sheet on a proportional
basis consistent with its ownership interest in the
 
investee company.
 
In addition, the company has historically
recorded finance lease assets and liabilities associated
 
with certain oil and gas joint ventures
 
on a proportional
basis pursuant to accounting guidance applicable
 
prior to January 1, 2019.
 
As of December 31, 2018, $
420
million of finance lease assets (net of accumulated
 
DD&A) and $
688
 
million of finance lease liabilities were
recorded on our consolidated balance sheet associated
 
with these leases.
 
In accordance with the transition
provisions of ASC Topic 842, and since we have elected to adopt the package of
 
optional transition-related
practical expedients, the historical accounting treatment
 
for these leases has been carried forward and is
 
subject
to reconsideration upon the modification or other required
 
reassessment of the arrangements prior to lease term
expiration.
 
 
In connection with our adoption of ASC Topic 842, we have recorded on our
 
consolidated balance sheet $
57
million of operating leases executed by investee
 
companies accounted for under the proportionate
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
106
 
consolidation method of accounting on a proportional
 
basis consistent with our ownership interest in the
investee company.
 
 
The following tables summarize the finance leases
 
amounts that were reflected on our consolidated
 
balance
sheet as of December 31, 2018, the operating leases
 
impact of adopting ASC Topic 842, and the right-of-use
asset and lease liability balances reflected for both operating
 
and finance leases on our consolidated balance
sheet as of December 31, 2019:
 
 
 
Millions of Dollars
Carrying Amount
Operating
Leases
Finance
Leases
Amounts recognized in line items in our Consolidated
Balance Sheet upon adoption of ASC Topic 842
Right-of-Use Assets
Properties, plants and equipment
Gross
$
1,044
Accumulated depreciation, depletion and amortization
(550)
Net properties, plants and equipment as of December
 
31, 2018
$
494
Adoption of ASC Topic 842 as of January 1, 2019
$
998
Lease Liabilities
Short-term debt
$
79
Long-term debt
698
Total finance leases debt as of December 31, 2018
$
777
Adoption of ASC Topic 842 as of January 1, 2019
$
998
Amounts recognized in line items in our Consolidated
Balance Sheet at December 31, 2019
Right-of-Use Assets
Properties, plants and equipment
Gross
$
1,039
Accumulated depreciation, depletion and amortization
(649)
Net properties, plants and equipment
*
$
390
Prepaid expenses and other current assets
$
40
Other assets
896
 
* Includes proportionately
 
consolidated finance lease assets
 
(net of accumulated depreciation,
 
depletion and amortization)
 
of $
335
 
million.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
107
 
Millions of Dollars
Carrying Amount
Operating
Leases
Finance
Leases
Lease Liabilities
Short-term debt
*
$
87
Other accruals
$
347
Long-term debt
*
633
Other liabilities and deferred credits
585
Total lease liabilities
$
932
$
720
 
Short-term debt
 
and
long-term debt
 
include proportionately
 
consolidated finance lease liabilities of $
56
 
million and $
579
 
million, respectively.
 
 
 
The following table summarizes our lease costs for 2019:
Millions of Dollars
2019
Lease Cost
*
Operating lease cost
$
341
Finance lease cost
Amortization of right-of-use assets
99
Interest on lease liabilities
37
Short-term lease cost
**
77
Total lease cost
***
$
554
 
*The amounts presented
 
in the table above have not been
 
adjusted to reflect amounts
 
recovered
 
or reimbursed from
 
oil and gas coventurers.
 
**Short-term leases
 
are not recorded
 
on our consolidated balance sheet.
 
Our future
short-term lease commitments
 
amount to $
31
 
million, of
 
which $
18
 
million is related to leases
 
whose terms have not yet
 
commenced as of December
 
31, 2019.
***Variable
 
lease cost and sublease income are
 
immaterial for the period presented
 
and therefore
 
are not included in the table
 
above
.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
108
 
The following table summarizes the lease terms and discount
 
rates:
December 31, 2019
Lease Term and Discount Rate
Weighted-average term (years)
Operating leases
5.19
Finance leases
8.70
Weighted-average discount rate (percent)
Operating leases
3.10
Finance leases
5.53
The following table summarizes other lease information
 
for 2019:
Millions of Dollars
2019
Other Information
*
Cash paid for amounts included in the measurement
 
of lease liabilities
Operating cash flows from operating leases
$
203
Operating cash flows from finance leases
27
Financing cash flows from finance leases
81
Right-of-use assets obtained in exchange for operating
 
lease liabilities
$
499
Right-of-use assets obtained in exchange for finance
 
lease liabilities
26
*The amounts presented
 
in the table above have not been adjusted
 
to reflect amounts recovered
 
or reimbursed from
 
oil and gas coventurers.
 
In
addition,
 
pursuant to other applicable
 
accounting guidance, lease payments made
 
in connection with preparing
 
another asset for its intended use
are reported
 
in the "Cash Flows From Investing
 
Activities" section of our consolidated
 
statement of cash flows.
 
 
The following table summarizes future lease payments
 
for operating and finance leases at December
 
31, 2019:
Millions of Dollars
Operating
Leases
Finance
 
Leases
Maturity of Lease Liabilities
2020
$
348
120
2021
247
104
2022
130
102
2023
82
88
2024
63
84
Remaining years
149
382
Total
*
1,019
880
Less: portion representing imputed interest
(87)
(160)
Total lease liabilities
$
932
720
*Future lease payments
 
for operating and finance leases
 
commencing on or after January
 
1, 2019, also include payments
 
related to non
 
-lease
components in accordance
 
with our election to adopt the
 
optional practical expedient not to separate
 
lease components apart from
 
non-lease
components for accounting
 
purposes.
 
In addition, future
 
payments related to operating
 
and finance leases proportionately
 
consolidated by the
company have been included
 
in the table on a proportionate
 
basis consistent with our respective
 
ownership interest
 
in the underlying investee
company or oil and gas
 
venture.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
109
 
At December 31, 2018, future minimum payments
 
due under finance (capital) leases pursuant
 
to
ASC Topic 840 were:
Millions
of Dollars
2019
$
118
2020
116
2021
100
2022
98
2023
87
Remaining years
453
Total
972
Less: portion representing imputed interest
(195)
Capital lease obligations
$
777
 
At December 31, 2018, future undiscounted minimum
 
rental payments due under noncancelable operating
leases pursuant to ASC Topic 840 were:
Millions
of Dollars
2019
$
248
2020
425
2021
136
2022
319
2023
54
Remaining years
212
Total
1,394
Less: income from subleases
(7)
Net minimum operating lease payments
$
1,387
 
For the years ended December 31, operating lease
 
rental expense pursuant to ASC Topic 840 was:
Millions of Dollars
2018
2017
Total rentals
$
253
264
Less: sublease rentals
(16)
(20)
$
237
244
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
110
 
Note 18—Employee Benefit Plans
 
 
Pension and Postretirement Plans
 
An analysis of the projected benefit obligations
 
for our pension plans and accumulated benefit
 
obligations for
our postretirement health and life insurance plans follows:
Millions of Dollars
Pension Benefits
Other Benefits
2019
2018
2019
2018
U.S.
Int’l.
U.S.
Int’l.
Change in Benefit Obligation
Benefit obligation at January 1
$
2,136
3,438
3,236
3,845
218
265
Service cost
79
69
83
81
1
1
Interest cost
79
97
99
107
8
8
Plan participant contributions
-
2
-
2
20
22
Plan amendments
-
-
-
7
-
-
Actuarial (gain) loss
278
387
(44)
(259)
27
(10)
Benefits paid
(253)
(147)
(507)
(143)
(59)
(67)
Curtailment
-
(69)
(4)
(3)
-
-
Settlement
-
-
(730)
-
-
-
Recognition of termination benefits
-
1
3
-
-
-
Foreign currency exchange rate change
-
102
-
(199)
1
(1)
Benefit obligation at December 31*
$
2,319
3,880
2,136
3,438
216
218
*Accumulated benefit obligation
 
portion of above at
 
December 31:
$
2,161
3,594
1,969
3,066
Change in Fair Value of Plan Assets
Fair value of plan assets at January 1
$
1,336
3,358
2,541
3,647
-
-
Actual return on plan assets
273
529
(112)
(106)
-
-
Company contributions
235
464
144
156
39
45
Plan participant contributions
-
2
-
2
20
22
Benefits paid
(253)
(147)
(507)
(143)
(59)
(67)
Settlement
-
-
(730)
-
-
-
Foreign currency exchange rate change
-
100
-
(198)
-
-
Fair value of plan assets at December 31
$
1,591
4,306
1,336
3,358
-
-
Funded Status
$
(728)
426
(800)
(80)
(216)
(218)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
111
 
Millions of Dollars
Pension Benefits
Other Benefits
2019
2018
2019
2018
U.S.
Int’l.
U.S.
Int’l.
Amounts Recognized in the
Consolidated Balance Sheet at
December 31
Noncurrent assets
$
-
765
-
232
-
-
Current liabilities
(21)
(6)
(59)
(4)
(42)
(44)
Noncurrent liabilities
(707)
(333)
(741)
(308)
(174)
(174)
Total recognized
$
(728)
426
(800)
(80)
(216)
(218)
Weighted-Average
 
Assumptions Used to
Determine Benefit Obligations at
December 31
Discount rate
3.25
%
2.35
4.25
3.05
3.10
4.05
Rate of compensation increase
4.00
3.35
4.00
3.65
-
Weighted-Average
 
Assumptions Used to
Determine Net Periodic Benefit Cost for
Years
 
Ended December 31
Discount rate
3.95
%
2.90
3.80
2.90
4.05
3.30
Expected return on plan assets
5.80
4.10
5.80
4.30
-
Rate of compensation increase
4.00
3.65
4.00
3.75
-
 
 
For both U.S. and international pensions, the overall
 
expected long-term rate of return is developed from the
expected future return of each asset class, weighted by
 
the expected allocation of pension assets to that
 
asset
class.
 
We rely on a variety of independent market forecasts in developing the expected rate of
 
return for each
class of assets.
 
Included in accumulated other comprehensive
 
income (loss) at December 31 were the following before-tax
 
amounts that had not been recognized in net periodic benefit
 
cost:
Millions of Dollars
Pension Benefits
Other Benefits
2019
2018
2019
2018
U.S.
Int’l.
U.S.
Int’l.
Unrecognized net actuarial (gain) loss
$
479
227
516
310
8
(21)
Unrecognized prior service cost (credit)
-
(2)
-
(4)
(183)
(216)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
112
 
Millions of Dollars
Pension Benefits
Other Benefits
2019
2018
2019
2018
U.S.
Int’l.
U.S.
Int’l.
Sources of Change in Other
Comprehensive Income (Loss)
Net gain (loss) arising during the period
$
(79)
51
(177)
17
(27)
10
Amortization of actuarial (gain) loss included
in income (loss)*
116
32
249
31
(2)
(1)
Net change during the period
$
37
83
72
48
(29)
9
Prior service credit (cost) arising during the
period
$
-
-
-
(7)
-
-
Amortization of prior service cost (credit)
included in income (loss)
-
(2)
-
(5)
(33)
(35)
Net change during the period
$
-
(2)
-
(12)
(33)
(35)
*Includes settlement losses
 
recognized in 2019
 
and 2018.
 
 
Included in accumulated other comprehensive
 
loss at December 31, 2019, were the following
 
before-tax
amounts that are expected to be amortized into
 
net periodic benefit cost during 2020:
Millions of Dollars
Pension
Other
Benefits
Benefits
U.S.
Int’l.
Unrecognized net actuarial (gain) loss
$
50
23
1
Unrecognized prior service credit
-
(2)
(31)
 
 
For our tax-qualified pension plans with projected benefit
 
obligations in excess of plan assets, the projected
benefit obligation, the accumulated benefit obligation,
 
and the fair value of plan assets were $
2,073
 
million,
$
1,919
 
million, and $
1,635
 
million, respectively, at December 31, 2019, and $
1,871
 
million, $
1,737
 
million,
and $
1,373
 
million, respectively, at December 31, 2018.
 
For our unfunded nonqualified key employee supplemental
 
pension plans, the projected benefit obligation
 
and
the accumulated benefit obligation were $
601
 
million and $
542
 
million, respectively, at December 31, 2019,
and were $
586
 
million and $
504
 
million, respectively, at December 31, 2018.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
113
 
The components of net periodic benefit cost of all defined
 
benefit plans are presented in the following table:
Millions of Dollars
Pension Benefits
Other Benefits
2019
2018
2017
2019
2018
2017
U.S.
Int’l.
U.S.
Int’l.
U.S.
Int’l.
Components of Net
Periodic Benefit Cost
Service cost
$
79
69
83
81
89
77
1
1
2
Interest cost
79
97
99
107
118
103
8
8
9
Expected return on plan
assets
(74)
(138)
(114)
(155)
(132)
(158)
-
-
-
Amortization of prior
service cost (credit)
-
(2)
-
(5)
4
(6)
(33)
(35)
(36)
Recognized net actuarial
loss (gain)
54
32
53
31
69
50
(2)
(1)
(3)
Settlements
62
-
196
-
131
-
-
-
-
Net periodic benefit cost
$
200
58
317
59
279
66
(26)
(27)
(28)
 
 
The components of net periodic benefit cost, other than
 
the service cost component, are included in
 
the “Other
expenses” line item on our consolidated income statement.
 
In 2018, we purchased a group annuity contract
 
from Prudential and transferred $
730
 
million of future benefit
obligations from the U.S. qualified pension plan to
 
Prudential.
 
The purchase of the group annuity contract was
funded directly by plan assets of the U.S. qualified pension
 
plan.
 
Effective January 1, 2019, the Cash Balance
Account (Title II) of the ConocoPhillips Retirement Plan, a
 
U.S. qualified pension plan, was closed to
 
new
entrants.
 
New employees and rehires on or after January
 
1, 2019, and employees that elected to opt out of
Title II will no longer receive pay credits to their Cash Balance Account
 
and instead will be eligible for a
Company Retirement Contribution (CRC) as described
 
in the Defined Contribution Plans section.
 
We
 
recognized pension settlement losses of $
62
 
million in 2019, $
196
 
million in 2018, and $
131
 
million in
2017 as lump-sum benefit payments from certain U.S. pension
 
plans exceeded the sum of service and interest
costs for those plans and led to recognition of settlement
 
losses.
 
The sale of two ConocoPhillips U.K. subsidiaries completed
 
during the third quarter of 2019 led to a
significant reduction of future services of active employees
 
in certain international pension plans, resulting in a
curtailment.
 
In conjunction with the recognition of the curtailment,
 
the fair market values of pension plan
assets were updated, the pension benefit obligation
 
was remeasured, and the net pension asset
 
decreased by
$
43
 
million, resulting in a corresponding decrease to other
 
comprehensive income.
 
This is primarily a result of
a decrease in the discount rate from
2.90
 
percent at December 31, 2018 to
1.80
 
percent at September 30, 2019
offset by a decrease in the pension benefit obligation from
 
curtailment.
 
In determining net pension and other postretirement
 
benefit costs, we amortize prior service costs on
 
a straight-
line basis over the average remaining service period of
 
employees expected to receive benefits under
 
the plan.
 
For net actuarial gains and losses, we amortize
10
 
percent of the unamortized balance each year.
 
We
 
have multiple nonpension postretirement
 
benefit plans for health and life insurance.
 
The health care plans
are contributory and subject to various cost sharing
 
features, with participant and company contributions
adjusted annually; the life insurance plans are noncontributory.
 
The measurement of the U.S. pre-65 retiree
medical accumulated postretirement benefit obligation
 
assumes a health care cost trend rate of
7
 
percent in
2020 that declines to
5
 
percent by
2028
.
 
The measurement of the U.S. post-65 retiree medical accumulated
postretirement benefit obligation assumes an ultimate health
 
care cost trend rate of
4
 
percent achieved in 2020
114
 
that increases to
5
 
percent by
2028
.
 
A one-percentage-point change in the assumed
 
health care cost trend rate
would be immaterial to ConocoPhillips.
 
 
Plan Assets
—We follow a policy of broadly diversifying pension plan assets across asset
 
classes and
individual holdings.
 
As a result, our plan assets have no significant
 
concentrations of credit risk.
 
Asset classes
that are considered appropriate include U.S. equities, non-U.S.
 
equities, U.S. fixed income, non-U.S. fixed
income, real estate and private equity investments.
 
Plan fiduciaries may consider and add other
 
asset classes to
the investment program from time to time.
 
The target allocations for plan assets are
37
 
percent equity
securities,
56
 
percent debt securities,
6
 
percent real estate and
1
 
percent other.
 
Generally, the plan investments
are publicly traded, therefore minimizing liquidity
 
risk in the portfolio.
 
 
The following is a description of the valuation methodologies
 
used for the pension plan assets.
 
There have
been no changes in the methodologies used at
 
December 31, 2019 and 2018.
●
 
Fair values of equity securities and government debt
 
securities categorized in Level 1 are primarily
based on quoted market prices in active markets for identical
 
assets and liabilities.
●
 
Fair values of corporate debt securities, agency and mortgage-backed
 
securities and government debt
securities categorized in Level 2 are estimated using recently
 
executed transactions and quoted market
prices for similar assets and liabilities in active markets
 
and for identical assets and liabilities in
markets that are not active.
 
If there have been no market transactions in a
 
particular fixed income
security, its fair value is calculated by pricing models that benchmark the security against
 
other
securities with actual market prices.
 
When observable quoted market prices are
 
not available, fair
value is based on pricing models that use something
 
other than actual market prices (e.g., observable
inputs such as benchmark yields, reported trades and
 
issuer spreads for similar securities), and these
securities are categorized in Level 3 of the fair value
 
hierarchy.
 
●
 
Fair values of investments in common/collective trusts
 
are determined by the issuer of each fund
based on the fair value of the underlying assets.
●
 
Fair values of mutual funds are based on quoted market
 
prices, which represent the net asset value
 
of
shares held.
●
 
Time deposits are valued at cost, which approximates fair value.
●
 
Cash is valued at cost, which approximates fair value.
 
Fair values of international
 
cash equivalents
categorized in Level 2 are valued using observable yield
 
curves, discounting and interest rates.
 
U.S.
cash balances held in the form of short-term fund
 
units that are redeemable at the measurement date
are categorized as Level 2.
●
 
Fair values of exchange-traded derivatives classified
 
in Level 1 are based on quoted market
 
prices.
 
For other derivatives classified in Level 2, the values
 
are generally calculated from pricing models
with market input parameters from third-party sources.
●
 
Fair values of insurance contracts are valued at the present
 
value of the future benefit payments owed
by the insurance company to the plans’ participants.
●
 
Fair values of real estate investments are valued using
 
real estate valuation techniques and other
methods that include reference to third-party sources
 
and sales comparables where available.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
115
 
●
 
A portion of U.S. pension plan assets is held as a
 
participating interest in an insurance annuity
contract, which is calculated as the market value of
 
investments held under this contract, less the
accumulated benefit obligation covered by the contract.
 
The participating interest is classified as
Level 3 in the fair value hierarchy as the fair value is
 
determined via a combination of quoted market
prices, recently executed transactions, and an actuarial
 
present value computation for contract
obligations.
 
At December 31, 2019, the participating interest
 
in the annuity contract was valued at
$
95
 
million and consisted of $
235
 
million in debt securities, less $
140
 
million for the accumulated
benefit obligation covered by the contract.
 
At December 31, 2018, the participating interest in the
annuity contract was valued at $
84
 
million and consisted of $
228
 
million in debt securities, less $
144
million for the accumulated benefit obligation covered
 
by the contract.
 
The net change from 2018 to
2019 is due to an increase in the fair value of the
 
underlying investments of $
7
 
million offset by a
decrease in the present value of the contract obligation
 
of $
4
 
million.
 
The participating interest is not
available for meeting general pension benefit
 
obligations in the near term.
 
No future company
contributions are required and no new benefits are
 
being accrued under this insurance annuity
contract.
 
The fair values of our pension plan assets at December
 
31, by asset class were as follows:
Millions of Dollars
U.S.
International
Level 1
Level 2
Level 3
Total
Level 1
Level 2
Level 3
Total
2019
Equity securities
U.S.
$
94
-
7
101
435
-
-
435
International
98
-
-
98
266
-
-
266
Mutual funds
93
-
-
93
245
267
-
512
Debt securities
Government
-
-
-
-
1,412
-
-
1,412
Corporate
-
2
-
2
-
-
-
-
Mutual funds
-
-
-
-
392
-
-
392
Cash and cash equivalents
-
-
-
-
98
-
-
98
Derivatives
-
-
-
-
11
-
-
11
Real estate
-
-
-
-
-
-
132
132
Total in fair value hierarchy
$
285
2
7
294
2,859
267
132
3,258
Investments measured at
 
net asset value*
Equity securities
Common/collective trusts
$
-
-
-
457
-
-
-
167
Debt securities
Common/collective trusts
-
-
-
637
-
-
-
760
Cash and cash equivalents
-
-
-
25
-
-
-
-
Real estate
-
-
-
83
-
-
-
112
Total**
$
285
2
7
1,496
2,859
267
132
4,297
 
*In accordance
 
with FASB
 
ASC Topic 715,
 
“Compensation
 
—Retirement Benefits,” certain
 
investments that are
 
to be measured
 
at fair value
 
 
using the net asset value
 
per share (or its equivalent)
 
practical expedient have
 
not been classified in the fair value
 
hierarchy.
 
The fair value
 
 
amounts presented
 
in this table are intended
 
to permit reconciliation
 
of the fair value hierarchy
 
to the amounts presented
 
in the Change in
 
Fair Value
 
of Plan Assets.
**Excludes the participating
 
interest in the insurance
 
annuity contract with a net asset of $
95
 
million and net receivables
 
related to security
 
 
transactions of $
9
 
million.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
116
 
The fair values of our pension plan assets at December
 
31, by asset class were as follows:
Millions of Dollars
U.S.
International
Level 1
Level 2
Level 3
Total
Level 1
Level 2
Level 3
Total
2018
Equity securities
U.S.
$
74
-
20
94
371
-
-
371
International
80
-
-
80
241
-
-
241
Mutual funds
76
-
-
76
213
181
-
394
Debt securities
Government
-
-
-
-
889
-
-
889
Corporate
-
2
-
2
-
-
-
-
Mutual funds
-
-
-
-
363
-
-
363
Cash and cash equivalents
-
-
-
-
71
-
-
71
Time deposits
-
-
-
-
6
-
-
6
Derivatives
-
-
-
-
(17)
-
-
(17)
Real estate
-
-
-
-
-
-
124
124
Total in fair value hierarchy
$
230
2
20
252
2,137
181
124
2,442
Investments measured at
 
net asset value*
Equity securities
Common/collective trusts
$
-
-
-
364
-
-
-
153
Debt securities
Common/collective trusts
-
-
-
548
-
-
-
641
Cash and cash equivalents
-
-
-
5
-
-
-
-
Real estate
-
-
-
80
-
-
-
109
Total**
$
230
2
20
1,249
2,137
181
124
3,345
 
*In accordance
 
with FASB
 
ASC Topic 715,
 
“Compensation
 
—Retirement Benefits,” certain
 
investments that are
 
to be measured
 
at
 
fair value
 
 
using the net asset value
 
per share (or its equivalent)
 
practical expedient have
 
not been classified in the fair value
 
hierarchy.
 
The fair value
 
 
amounts presented
 
in this table are intended
 
to permit reconciliation
 
of the fair value hierarchy
 
to the amounts presented
 
in the Change in
 
 
Fair Value
 
of Plan Assets.
**Excludes the participating
 
interest in the insurance
 
annuity contract with a net asset of $
84
 
million and net receivables
 
related to security
 
 
transactions of $
16
 
million.
 
 
 
Level 3 activity was not material for all periods.
 
Our funding policy for U.S. plans is to contribute at
 
least the minimum required by the Employee
 
Retirement
Income Security Act of 1974 and the Internal Revenue
 
Code of 1986, as amended.
 
Contributions to foreign
plans are dependent upon local laws and tax regulations.
 
In 2020, we expect to contribute approximately $
350
million to our domestic qualified and nonqualified pension
 
and postretirement benefit plans and $
90
 
million to
our international qualified and nonqualified pension
 
and postretirement benefit plans.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
117
 
The following benefit payments, which are exclusive
 
of amounts to be paid from the insurance annuity
 
contract
and which reflect expected future service, as appropriate,
 
are expected to be paid:
Millions of Dollars
Pension
Other
Benefits
Benefits
U.S.
Int’l.
2020
$
447
150
32
2021
270
156
29
2022
250
158
27
2023
217
163
24
2024
220
170
22
2025–2029
822
927
64
 
 
Severance Accrual
The following table summarizes our severance accrual
 
activity for the year ended December 31, 2019:
 
Millions of Dollars
Balance at December 31, 2018
$
48
Accruals
(1)
Benefit payments
(24)
Balance at December 31, 2019
$
23
 
 
Of the remaining balance at December
 
31, 2019, $
5
 
million is classified as short-term.
 
 
Defined Contribution Plans
 
Most U.S. employees are eligible to participate in
 
the ConocoPhillips Savings Plan (CPSP).
 
Employees can
deposit up to
75
 
percent of their eligible pay, subject to statutory limits, in the CPSP to a choice of
approximately
17
 
investment options.
 
Employees who participate in the CPSP and contribute
1
 
percent of
their eligible pay receive a
6
 
percent company cash match
 
with a potential company discretionary cash
contribution of up to
6
 
percent.
 
Effective January 1, 2019, new employees, rehires, and employees
 
that elected
to opt out of Title II are eligible to receive a CRC of
6
 
percent of eligible pay into their CPSP.
 
After
three years
 
of service with the company, the employee is
100
 
percent vested in any CRC.
 
Company
contributions charged to expense for the CPSP and predecessor
 
plans were $
82
 
million in 2019, $
82
 
million in
2018, and $
77
 
million in 2017.
 
We
 
have several defined contribution plans
 
for our international employees, each with
 
its own terms and
eligibility depending on location.
 
Total compensation expense recognized for these international plans was
approximately $
30
 
million in 2019, $
31
 
million in 2018, and $
35
 
million in 2017.
 
Share-Based Compensation Plans
 
The 2014 Omnibus Stock and Performance Incentive
 
Plan of ConocoPhillips (the Plan) was approved
 
by
shareholders in May 2014.
 
Over its
10
-year life, the Plan allows the issuance of up to
79
 
million shares of our
common stock for compensation to our employees
 
and directors; however, as of the effective date of the Plan,
(i) any shares of common stock available for future
 
awards under the prior plans and (ii) any shares
 
of common
stock represented by awards granted under the prior
 
plans that are forfeited, expire or are cancelled
 
without
delivery of shares of common stock or which result
 
in the forfeiture of shares of common
 
stock back to the
company shall be available for awards under the Plan,
 
and no new awards shall be granted under
 
the prior
plans.
 
Of the 79 million shares available for issuance
 
under the Plan, no more than
40
 
million shares of
common stock are available for incentive stock options.
 
The Human Resources and Compensation Committee
 
 
 
 
 
 
 
 
 
 
 
 
118
 
of our Board of Directors is authorized to determine
 
the types, terms, conditions and limitations
 
of awards
granted.
 
Awards may be granted in the form of, but not limited to, stock options, restricted
 
stock units and
performance share units to employees and non-employee
 
directors who contribute to the company’s continued
success and profitability.
 
Total share-based compensation expense is measured using the grant date fair
 
value for our equity-classified
awards and the settlement date fair value for our liability-classified
 
awards.
 
We recognize share-based
compensation expense over the shorter of the service
 
period (i.e., the stated period of time required
 
to earn the
award); or the period beginning at the start of the service
 
period and ending when an employee first becomes
eligible for retirement, but not less than six months,
 
as this is the minimum period of time required
 
for an
award to not be subject to forfeiture.
 
Our share-based compensation programs generally
 
provide accelerated
vesting (i.e., a waiver of the remaining period of service
 
required to earn an award) for awards held by
employees at the time of their retirement.
 
Some of our share-based awards vest ratably (i.e., portions
 
of the
award vest at different times) while some of our awards cliff vest (i.e., all
 
of the award vests at the same time).
 
We
 
recognize expense on a straight-line basis over the
 
service period for the entire award, whether
 
the award
was granted with ratable or cliff vesting.
 
 
Compensation Expense
—Total share-based compensation expense recognized in income (loss) and
 
the
associated tax benefit for the years ended December
 
31 were as follows:
Millions of Dollars
2019
2018
2017
Compensation cost
$
274
265
227
Tax benefit
71
64
76
 
Stock Options
—
Stock options granted under the provisions of the Plan and prior plans permit purchase of our
common stock at exercise prices equivalent to the average fair market value of ConocoPhillips common stock
on the date the options were granted. The options have terms of 10 years and generally vest ratably, with one-
third of the options awarded vesting and becoming exercisable on each anniversary date following the date of
grant. Options awarded to certain employees already eligible for retirement vest within six months of the grant
date, but those options do not become exercisable until the end of the normal vesting period. Beginning in
2018, stock option grants were discontinued and replaced with three-year, time-vested restricted stock units
which generally will be cash-settled.
 
The fair market values of the options granted in 2017 were
 
measured on the date of grant using the
Black-Scholes-Merton option-pricing model.
 
The weighted-average assumptions used were
 
as follows:
2017
Assumptions used
Risk-free interest rate
2.24
%
Dividend yield
4.00
%
Volatility
 
factor
28.12
%
Expected life (years)
6.39
 
 
There were no ranges in the assumptions used to
 
determine the fair market values of our options
 
granted in
2017.
 
We
 
believe our historical volatility
 
for periods prior to the 2012 separation of our Downstream
 
businesses is no
longer relevant in estimating expected volatility.
 
For 2017,
 
expected volatility was based on the weighted-
average blend of the company’s historical stock price volatility
 
from May 1, 2012 (the date of separation of our
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
119
 
Downstream businesses) through the stock option
 
grant date and the average historical stock
 
price volatility of
a group of peer companies for the expected term of
 
the options.
 
The following summarizes our stock option activity
 
for the year ended December 31, 2019:
Millions of Dollars
Weighted-Average
Aggregate
Options
Exercise Price
Intrinsic Value
Outstanding at December 31, 2018
19,379,677
$
52.88
$
214
Exercised
(1,339,480)
36.28
39
Forfeited
-
Expired or cancelled
-
Outstanding at December 31, 2019
18,040,197
$
54.11
$
206
Vested at
 
December 31, 2019
17,922,026
$
54.14
$
205
Exercisable at December 31, 2019
17,172,815
$
54.33
$
194
 
 
The weighted-average remaining contractual term
 
of outstanding options, vested options and exercisable
options at December 31, 2019, was
4.43
 
years,
4.41
 
years and
4.29
 
years, respectively.
 
The weighted-average
grant date fair value of stock option awards granted
 
during 2017 was $
9.18
.
 
The aggregate intrinsic value of
options exercised was $
94
 
million in 2018 and $
4
 
million in 2017.
 
 
During 2019, we received $
49
 
million in cash and realized
 
a tax benefit of $
13
 
million from the exercise of
options.
 
At December 31, 2019, the remaining unrecognized
 
compensation expense from unvested options
was
zero
.
 
Stock Unit Program—
Generally, restricted stock units are granted annually under the provisions of the Plan
and vest in an aggregate installment on the third anniversary of the grant date. In addition, restricted stock
units granted under the Plan for a variable long-term incentive program vest ratably in three equal annual
installments beginning on the first anniversary of the grant date. Restricted stock units are also granted ad hoc
to attract or retain key personnel, and the terms and conditions under which these restricted stock units vest
vary by award
.
 
Stock-Settled
Upon vesting, these restricted stock units are settled by issuing one share of ConocoPhillips common stock per
unit. Units awarded to retirement eligible employees vest six months from the grant date; however, those units
are not issued as common stock until the earlier of separation from the company or the end of the regularly
scheduled vesting period. Until issued as stock, most recipients of the restricted stock units receive a quarterly
cash payment of a dividend equivalent that is charged to retained earnings. The grant date fair market value of
these restricted stock units is deemed equal to the average ConocoPhillips stock price on the grant date. The
grant date fair market value of units that do not receive a dividend equivalent while unvested is deemed equal
to the average ConocoPhillips stock price on the grant date, less the net present value of the dividends that will
not be received
.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
120
 
The following summarizes our stock-settled stock
 
unit activity for the year ended December 31,
 
2019:
Weighted-Average
Millions of Dollars
Stock Units
Grant Date Fair Value
Total Fair Value
Outstanding at December 31, 2018
7,546,973
$
43.41
Granted
2,045,503
67.77
Forfeited
(99,748)
62.93
Issued
(3,269,682)
34.32
$
225
Outstanding at December 31, 2019
6,223,046
$
55.99
Not Vested at December 31, 2019
4,185,141
56.17
 
 
At December 31, 2019,
 
the remaining unrecognized compensation cost
 
from the unvested stock-settled units
was $
93
 
million, which will be recognized over
 
a weighted-average period of
1.71
 
years, the longest period
being
2.73
 
years.
 
The weighted-average grant date fair value of stock
 
unit awards granted during 2018 and
2017 was $
52.45
 
and $
48.77
, respectively.
 
The total fair value of stock units issued during
 
2018 and 2017 was
$
154
 
million and $
159
 
million, respectively.
 
Cash-Settled
Beginning in 2018, cash-settled executive restricted stock units replaced the stock option program. These
restricted stock units, subject to elections to defer, will be settled in cash equal to the fair market value of a
share of ConocoPhillips common stock per unit on the settlement date and are classified as liabilities on the
balance sheet. Units awarded to retirement eligible employees vest six months from the grant date; however,
those units are not settled until the earlier of separation from the company or the end of the regularly scheduled
vesting period. Compensation expense is initially measured using the average fair market value of
ConocoPhillips common stock and is subsequently adjusted, based on changes in the ConocoPhillips stock
price through the end of each subsequent reporting period, through the settlement date. Recipients receive an
accrued reinvested dividend equivalent that is charged to compensation expense. The accrued reinvested
dividend is paid at the time of settlement, subject to the terms and conditions of the award.
 
 
The following summarizes our cash-settled stock unit activity
 
for the year ended December 31, 2019:
Weighted-Average
Millions of Dollars
Stock Units
Grant Date Fair Value
Total Fair Value
Outstanding at December 31, 2018
376,608
$
62.21
Granted
319,552
68.20
Forfeited
(6,914)
61.35
Issued
(92,255)
61.61
$
6
Outstanding at December 31, 2019
596,991
$
64.54
Not Vested at December 31, 2019
153,457
64.54
 
At December 31, 2019,
 
the remaining unrecognized compensation cost
 
from the unvested cash-settled units
was $
5
 
million, which will be recognized over
 
a weighted-average period of
1.70
 
years, the longest period
being
2.12
 
years.
 
The weighted-average grant date fair value of stock
 
unit awards granted during 2018 was
$
53.68
.
 
The total fair value of stock units issued during
 
2018 was $
1
 
million.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
121
 
Performance Share Program
—Under the Plan, we also annually grant restricted
 
performance share units
(PSUs) to senior management.
 
These PSUs are authorized three years prior
 
to their effective grant date (the
performance period).
 
Compensation expense is initially measured using
 
the average fair market value of
ConocoPhillips common stock and is subsequently
 
adjusted, based on changes in the ConocoPhillips
 
stock
price through the end of each subsequent reporting period,
 
through the grant date for stock-settled awards and
the settlement date for cash-settled awards.
 
 
Stock-Settled
For performance periods beginning before 2009, PSUs do not vest until the employee becomes eligible for
retirement by reaching age 55 with five years of service, and restrictions do not lapse until the employee
separates from the company. With respect to awards for performance periods beginning in 2009 through 2012,
PSUs do not vest until the earlier of the date the employee becomes eligible for retirement by reaching age 55
with five years of service or five years after the grant date of the award, and restrictions do not lapse until the
earlier of the employee’s separation from the company or five years after the grant date (although recipients
can elect to defer the lapsing of restrictions until separation). We recognize compensation expense for these
awards beginning on the grant date and ending on the date the PSUs are scheduled to vest. Since these awards
are authorized three years prior to the grant date, for employees eligible for retirement by or shortly after the
grant date, we recognize compensation expense over the period beginning on the date of authorization and
ending on the date of grant. Until issued as stock, recipients of the PSUs receive a quarterly cash payment of a
dividend equivalent that is charged to retained earnings. Beginning in 2013, PSUs authorized for future grants
will vest, absent employee election to defer, upon settlement following the conclusion of the three-year
performance period. We recognize compensation expense over the period beginning on the date of
authorization and ending on the conclusion of the performance period. PSUs are settled by issuing one share
of ConocoPhillips common stock per unit.
 
The following summarizes our stock-settled Performance Share
 
Program activity for the year ended
December 31, 2019:
Weighted-Average
Millions of Dollars
Stock Units
Grant Date Fair Value
Total Fair Value
Outstanding at December 31, 2018
2,335,542
$
50.45
Granted
77,841
68.90
Forfeited
-
Issued
(388,559)
53.66
$
25
Outstanding at December 31, 2019
2,024,824
$
50.55
Not Vested at December 31, 2019
15,616
$
47.80
 
 
At December 31, 2019,
 
the remaining unrecognized compensation cost
 
from unvested stock-settled
performance share awards was
zero
.
 
The weighted-average grant date fair value of stock-settled
 
PSUs granted
during 2018 and 2017 was $
53.28
 
and $
49.76
, respectively.
 
The total fair value of stock-settled PSUs issued
during 2018 and 2017 was $
29
 
million and $
57
 
million, respectively.
 
Cash-Settled
In connection with and immediately following the
 
separation of our Downstream businesses in
 
2012, grants of
new PSUs, subject to a shortened performance period,
 
were authorized.
 
Once granted, these PSUs vest, absent
employee election to defer, on the earlier of five years after the
 
grant date of the award or the date the
employee becomes eligible for retirement.
 
For employees eligible for retirement
 
by or shortly after the grant
date, we recognize compensation expense over the
 
period beginning on the date of authorization and
 
ending on
the date of grant.
 
Otherwise, we recognize compensation expense
 
beginning on the grant date and ending
 
on
the date the PSUs are scheduled to vest.
 
These PSUs are settled in cash equal to
 
the fair market value of a
share of ConocoPhillips common stock per unit
 
on the settlement date and thus are classified
 
as liabilities on
the balance sheet.
 
Until settlement occurs, recipients of the PSUs receive
 
a quarterly cash payment of a
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
122
 
dividend equivalent that is charged to compensation expense.
 
Beginning in 2013, PSUs authorized for future grants
 
will vest upon settlement following the conclusion
 
of the
three-year performance period.
 
We recognize compensation expense over the period beginning on the date of
authorization and ending at the conclusion of the performance
 
period.
 
These PSUs will be settled in cash equal
to the fair market value of a share of ConocoPhillips
 
common stock per unit on the settlement date
 
and are
classified as liabilities on the balance sheet.
 
For performance periods beginning before
 
2018, during the
performance period, recipients of the PSUs do not
 
receive a quarterly cash payment of a
 
dividend equivalent,
but after the performance period ends, until settlement
 
in cash occurs, recipients of the PSUs receive a
quarterly cash payment of a dividend equivalent that
 
is charged to compensation expense.
 
For the performance
period beginning in 2018, recipients of the PSUs receive
 
an accrued reinvested dividend equivalent
 
that is
charged to compensation expense.
 
The accrued reinvested dividend is paid at the
 
time of settlement, subject to
the terms and conditions of the award.
 
 
The following summarizes our cash-settled Performance
 
Share Program activity for the year ended
December 31, 2019:
Weighted-Average
Millions of Dollars
Stock Units
Grant Date Fair Value
Total Fair Value
Outstanding at December 31, 2018
1,131,007
$
62.21
Granted
1,958,043
68.90
Forfeited
-
Settled
(2,479,776)
69.10
$
171
Outstanding at December 31, 2019
609,274
$
64.54
Not Vested at December 31, 2019
38,487
$
64.54
 
 
At December 31, 2019,
 
the remaining unrecognized compensation cost
 
from unvested cash-settled
performance share awards was
zero
.
 
The weighted-average grant date fair value of cash-settled
 
PSUs granted
during 2018 and 2017 was $
53.28
 
and $
49.76
, respectively.
 
The total fair value of cash-settled performance
share awards settled during 2018 and 2017 was $
22
 
million and $
24
 
million, respectively.
 
From inception of the Performance Share Program through
 
2013, approved PSU awards were granted after the
conclusion of performance periods.
 
Beginning in February 2014, initial target PSU awards are issued near the
beginning of new performance periods. These initial target PSU awards will terminate at the end of the
performance periods and will be settled after the performance periods have ended. Also in 2014, initial target
PSU awards were issued for open performance periods that began in prior years. For the open performance
period beginning in 2012, the initial target PSU awards terminated at the end of the three-year performance
period and were replaced with approved PSU awards. For the open performance period beginning in 2013, the
initial target PSU awards terminated at the end of the three-year performance period and were settled after the
performance period ended.
 
There is no effect on recognition of compensation
 
expense.
 
 
Other
—In addition to the above active programs, we
 
have outstanding shares of restricted stock
 
and restricted
stock units that were either issued as part of our non-employee
 
director compensation program for current and
former members of the company’s Board of Directors or as part of an executive compensation
 
program that
has been discontinued.
 
Generally, the recipients of the restricted shares or units receive a quarterly dividend
 
or
dividend equivalent.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
123
 
The following summarizes the aggregate activity
 
of these restricted shares and units for the
 
year ended
December 31, 2019:
Weighted-Average
Millions of Dollars
Stock Units
Grant Date Fair Value
Total Fair Value
Outstanding at December 31, 2018
1,107,315
$
46.57
Granted
64,063
63.58
Cancelled
(2,307)
23.73
Issued
(177,163)
49.23
$
11
Outstanding at December 31, 2019
991,908
$
47.24
 
 
At December 31, 2019, all outstanding restricted stock
 
and restricted stock units were fully vested and
 
there
was
no
 
remaining compensation cost to be recorded.
 
The weighted-average grant date fair value of
 
awards
granted during 2018 and 2017 was $
62.01
 
and $
48.87
, respectively.
 
The total fair value of awards issued
during 2018 and 2017 was $
17
 
million and $
4
 
million, respectively.
 
 
 
Note 19—Income Taxes
Income taxes charged to net income (loss) were:
Millions of Dollars
2019
2018
2017
Income Taxes
Federal
Current
$
18
4
79
Deferred
(113)
545
(3,046)
Foreign
Current
2,545
3,273
1,729
Deferred
(323)
(166)
(510)
State and local
Current
148
108
51
Deferred
(8)
(96)
(125)
$
2,267
3,668
(1,822)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
124
 
Deferred income taxes reflect the net tax effect of temporary
 
differences between the carrying amounts of
assets and liabilities for financial reporting purposes
 
and the amounts used for tax purposes.
 
Major components
of deferred tax liabilities and assets at December
 
31 were:
Millions of Dollars
2019
2018
Deferred Tax Liabilities
PP&E and intangibles
$
8,660
8,004
Inventory
35
60
Deferred state income tax
-
61
Other
234
156
Total deferred tax liabilities
8,929
8,281
Deferred Tax Assets
Benefit plan accruals
542
641
Asset retirement obligations and accrued environmental
 
costs
2,339
2,891
Investments in joint ventures
1,722
104
Other financial accruals and deferrals
777
330
Loss and credit carryforwards
8,968
2,378
Other
345
398
Total deferred tax assets
14,693
6,742
Less: valuation allowance
(10,214)
(3,040)
Net deferred tax assets
4,479
3,702
Net deferred tax liabilities
$
4,450
4,579
 
 
At December 31, 2019, noncurrent assets and liabilities
 
included deferred taxes of $
184
 
million and
$
4,634
 
million, respectively.
 
At December 31, 2018, noncurrent assets and liabilities
 
included deferred taxes
of $
442
 
million and $
5,021
 
million, respectively.
 
At December 31, 2019, the components of our loss and
 
credit carryforwards before and after consideration
 
of
the applicable valuation allowances were:
Millions of Dollars
Net Deferred
Expiration of
Gross Deferred
Tax Asset After
Net Deferred
Tax Asset
Valuation
 
Allowance
Tax Asset
U.S. foreign tax credits
$
7,696
14
2028
U.S. general business credits
250
250
2036-2038
U.S. capital loss
202
32
2024
State net operating losses and tax credits
370
50
Various
Foreign net operating losses and tax credits
450
413
Post 2025
$
8,968
759
 
 
Valuation
 
allowances have been established to reduce
 
deferred tax assets to an amount that will, more
 
likely
than not, be realized.
 
During 2019, valuation allowances increased a
 
total of $
7,174
 
million.
 
The increase
primarily relates to deferred tax assets recognized during
 
2019 as a result of the finalization of rules related to
the U.S. Tax Cuts and Jobs Act (Tax Legislation including ongoing issuance of tax regulations related to such
legislation), as further discussed below.
 
Based on our historical taxable income,
 
expectations for the future,
and available tax-planning strategies, management
 
expects deferred tax assets, net of valuation allowance,
 
will
primarily be realized as offsets to reversing deferred tax liabilities.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
125
 
 
On December 2, 2019, the Internal Revenue Service finalized
 
foreign tax credit regulations related to the 2017
Tax Cuts
 
and Jobs Act.
 
Due to the finalization of these regulations,
 
in the fourth quarter of 2019 we
recognized $
151
 
million of net deferred tax assets.
 
Correspondingly, we recorded $
6,642
 
million of existing
foreign tax credit carryovers where recognition
 
was previously considered to be remote.
 
Present legislation
still makes their realization unlikely and therefore these
 
credits have been offset with a full valuation
allowance.
 
 
At December 31, 2019, unremitted income considered
 
to be permanently reinvested in certain
 
foreign
subsidiaries and foreign corporate joint ventures
 
totaled approximately $
4,196
 
million.
 
Deferred income taxes
have not been provided on this amount, as we
 
do not plan to initiate any action that would
 
require the payment
of income taxes.
 
The estimated amount of additional tax, primarily local
 
withholding tax, that would be
payable on this income if distributed is approximately
 
$
210
 
million.
 
The following table shows a reconciliation of the beginning
 
and ending unrecognized tax benefits for 2019,
2018 and 2017:
Millions of Dollars
2019
2018
2017
Balance at January 1
$
1,081
882
381
Additions based on tax positions related to the current
 
year
9
268
612
Additions for tax positions of prior years
120
43
109
Reductions for tax positions of prior years
(22)
(73)
(129)
Settlements
(9)
(35)
(5)
Lapse of statute
(2)
(4)
(86)
Balance at December 31
$
1,177
1,081
882
 
 
Included in the balance of unrecognized tax benefits
 
for 2019, 2018 and 2017 were $
1,100
 
million,
$
1,081
 
million and $
882
 
million, respectively, which, if recognized, would impact our effective tax rate.
 
The
balance of the unrecognized tax benefits increased in 2019
 
mainly due to the treatment of our PDVSA
settlement. The balance of the unrecognized tax benefits
 
increased in 2018 mainly due to the treatment
 
of
distributions from certain foreign subsidiaries.
 
The balance of unrecognized tax benefits increased
 
in 2017
mainly due to the recognition of a U.S. worthless securities
 
deduction that we do not believe will generate a
cash tax benefit.
 
See Note 13—Contingencies and Commitments,
 
for more information on the PDVSA
settlement.
 
 
At December 31, 2019, 2018 and 2017, accrued liabilities
 
for interest and penalties totaled $
42
 
million,
$
45
 
million and $
54
 
million, respectively, net of accrued income taxes.
 
Interest and penalties resulted in a
benefit to earnings of $
3
 
million in 2019, a benefit to earnings
 
of $
4
 
million in 2018, and
no
 
impact to earnings
in 2017.
 
 
We
 
file tax returns in the U.S. federal jurisdiction and
 
in many foreign and state jurisdictions.
 
Audits in major
jurisdictions are generally complete as follows: U.K.
 
(2015), Canada (2014), U.S.
 
(2014) and Norway (2018).
 
Issues in dispute for audited years and audits for
 
subsequent years are ongoing and in various stages
 
of
completion in the many jurisdictions in which we
 
operate around the world.
 
Consequently, the balance in
unrecognized tax benefits can be expected to fluctuate
 
from period to period.
 
It is reasonably possible such
changes could be significant when compared with
 
our total unrecognized tax benefits, but the amount
 
of
change is not estimable.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
126
 
The amounts of U.S. and foreign income (loss)
 
before income taxes, with a reconciliation
 
of tax at the federal
statutory rate with the provision for income taxes,
 
were:
Millions of Dollars
Percent of Pre-Tax Income (Loss)
2019
2018
2017
2019
2018
2017
Income (loss) before income taxes
United States
$
4,704
2,867
(5,250)
49.4
%
28.7
200.8
Foreign
4,820
7,106
2,635
50.6
71.3
(100.8)
$
9,524
9,973
(2,615)
100.0
%
100.0
100.0
Federal statutory income tax
$
2,000
2,095
(915)
21.0
%
21.0
35.0
Non-U.S. effective tax rates
1,399
1,766
625
14.7
17.7
(23.9)
Tax Legislation
-
(10)
(852)
-
(0.1)
32.6
Canada disposition
-
-
(1,277)
-
-
48.8
U.K. disposition
(732)
(150)
-
(7.7)
(1.5)
-
Recovery of outside basis
(77)
(21)
(962)
(0.8)
(0.2)
36.8
Adjustment to tax reserves
9
(4)
881
0.1
-
(33.7)
Adjustment to valuation allowance
(225)
(26)
-
(2.4)
(0.3)
-
APLNG impairment
-
-
834
-
-
(31.9)
State income tax
123
135
(84)
1.3
1.4
3.2
Malaysia Deepwater Incentive
(164)
-
-
(1.7)
-
-
Enhanced oil recovery credit
(27)
(99)
(68)
(0.3)
(1.0)
2.6
Other
(39)
(18)
(4)
(0.4)
(0.2)
0.2
$
2,267
3,668
(1,822)
23.8
%
36.8
69.7
 
 
Our effective tax rate for 2019 was favorably impacted by
 
the sale of two of our U.K. subsidiaries. The
disposition generated a before-tax gain of more than $
1.7
 
billion with an associated tax benefit of $
335
million. The disposition generated a U.S. capital loss
 
of approximately $
2.1
 
billion which has generated a U.S.
tax benefit of approximately $
285
 
million. The remaining U.S. capital loss has
 
been recorded as a deferred tax
asset fully offset with a valuation allowance.
 
See Note 5—Asset Acquisitions and Dispositions, for additional
information on the disposition.
 
 
During the third quarter of 2019, we received final
 
partner approval in Malaysia Block G to claim
 
certain
deepwater tax credits. As a result, we recorded an income
 
tax benefit of $
164
 
million.
 
 
The decrease in the effective tax rate for 2018 was primarily
 
due to the impact of the Clair Field disposition
 
in
the U.K. and our overall income position, partially
 
offset by our mix of income among taxing jurisdictions.
 
 
Our effective tax rate for 2018 was favorably impacted by
 
the sale of a U.K. subsidiary to BP.
 
The subsidiary
held 16.5 percent of our 24 percent interest in the
 
BP-operated Clair Field in the U.K.
 
The disposition
generated a before-tax gain of $
715
 
million with no associated tax cost.
 
See Note 5—Asset Acquisitions and
Dispositions, for additional information on the disposition.
 
 
Tax Legislation was enacted in the U.S.
 
on December 22, 2017, reducing the U.S.
 
federal corporate income tax
rate to 21 percent from 35 percent, requiring companies
 
to pay a one-time transition tax on earnings
 
of certain
foreign subsidiaries that were previously tax deferred
 
and creating new taxes on certain foreign-sourced
earnings.
 
 
 
 
 
 
 
127
 
SAB 118 measurement period
 
We
 
applied the guidance in Staff Accounting Bulletin No.
 
118 when accounting for the enactment-date effects
of Tax Legislation in 2017 and throughout 2018.
 
At December 31, 2017, we had not completed our
accounting for all the enactment-date income tax effects
 
of Tax Legislation under ASC 740, Income Taxes, for
the remeasurement of deferred tax assets and liabilities
 
and the one-time transition tax.
 
As of December 31,
2018, we had
 
completed our accounting for all the enactment-date
 
income tax effects of Tax Legislation.
 
As
further discussed below, during 2018, we recognized adjustments of $
10
 
million to the provisional amounts
recorded at December 31, 2017, and included these adjustments
 
as a component
 
of income tax provision.
 
 
Provisional Amounts—Foreign tax effects
 
The one-time transition tax is based on our total post-1986
 
earnings, the tax on which we previously deferred
from U.S. income taxes under U.S. law.
 
We estimated at December 31, 2017, that we would not incur a one-
time transition tax.
 
Upon further analyses of Tax Legislation and Notices and regulations issued
 
and proposed
by the U.S. Department of the Treasury and the Internal Revenue Service,
 
we finalized our calculations of the
transition tax liability during 2018.
 
Based upon this analysis, we did not incur
 
a one-time transition tax.
 
 
As a result of the Tax Legislation, we removed the indefinite reinvestment assertion on one
 
of our foreign
subsidiaries and recorded a tax expense of $
56
 
million in the fourth quarter of 2017.
 
 
Deferred tax assets and liabilities
 
As of December 31, 2017, we remeasured certain deferred
 
tax assets and liabilities based on the rates at which
they were expected to reverse in the future (which was
 
generally 21 percent), by recording a provisional
amount of $
908
 
million.
 
Upon further analysis of certain aspects
 
of Tax Legislation and refinement of our
calculations during the 12 months ended December
 
31, 2018, we adjusted our provisional
 
amount by $
10
million, which is included as a component of income tax
 
expense.
 
 
 
Global intangible low-taxed income (GILTI)
 
We
 
have elected to account for GILTI in the year the tax is incurred.
 
For 2019 and 2018,
 
the current-year U.S.
income tax impact related to GILTI activities is immaterial.
 
 
Our effective tax rate in 2017 was favorably impacted by a
 
tax benefit of $
1,277
 
million related to the Canada
disposition.
 
This tax benefit was primarily associated with
 
a deferred tax recovery related to the Canadian
capital gains exclusion component of the 2017 Canada
 
disposition and the recognition of previously
unrealizable Canadian capital asset tax basis.
 
The Canada disposition, along with the
 
associated restructuring
of our Canadian operations, may generate an additional
 
tax benefit of $
822
 
million.
 
However, since we
believe it is not likely we will receive a corresponding
 
cash tax savings, this $
822
 
million benefit has been
offset by a full tax reserve.
 
See Note 5—Asset Acquisitions and Dispositions
 
for additional information on our
Canada disposition.
 
 
The impairment of our APLNG investment in the second quarter
 
of 2017 did not generate a tax benefit.
 
See
the “APLNG” section of Note 6—Investments, Loans and
 
Long-Term Receivables, for information on the
impairment of our APLNG investment.
 
 
 
Certain operating losses in jurisdictions outside of
 
the U.S.
 
only yield a tax benefit in the U.S.
 
as a worthless
security deduction.
 
For 2019, 2018 and 2017, before consideration
 
of unrecorded tax benefits discussed above,
the amount of the tax benefit was $
9
 
million, $
36
 
million and $
962
 
million, respectively.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
128
 
Note 20—Accumulated Other Comprehensive Loss
Accumulated other comprehensive loss in the equity
 
section of the balance sheet included:
Millions of Dollars
Defined
Benefit Plans
Net
Unrealized
Loss on
Securities
Foreign
Currency
Translation
Accumulated
Other
Comprehensive
Loss
December 31, 2016
$
(547)
-
(5,646)
(6,193)
Other comprehensive income (loss)
147
(58)
586
675
December 31, 2017
(400)
(58)
(5,060)
(5,518)
Other comprehensive income (loss)
39
-
(642)
(603)
Cumulative effect of adopting ASU No. 2016-01*
-
58
-
58
December 31, 2018
(361)
-
(5,702)
(6,063)
Other comprehensive income
51
-
695
746
Cumulative effect of adopting ASU No. 2018-02**
(40)
-
-
(40)
December 31, 2019
$
(350)
-
(5,007)
(5,357)
 
*We
 
adopted ASU No. 2016-01,
 
"Recognition and Measurement
 
of Financial Assets and Liabilities," beginning
 
January 1, 2018.
 
**See Note 2
—
Changes in Accounting Principles
 
for additional information.
During 2019, we recognized $
483
 
million of foreign currency translation adjustments
 
related to the completion
of our sale of two ConocoPhillips U.K. subsidiaries.
 
For additional information related
 
to this disposition, see
Note 5—Asset Acquisitions and Dispositions.
There were no items within accumulated other comprehensive
 
loss related to noncontrolling interests.
The following table summarizes reclassifications out
 
of accumulated other comprehensive loss during the
 
years
ended December 31:
Millions of Dollars
2019
2018
Defined Benefit Plans
$
88
189
Above amounts are
 
included in the computation
 
of net periodic benefit cost and
 
are presented
 
net of tax expense of:
$
23
50
See Note 18—Employee Benefit
 
Plans, for additional information.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
129
 
Note 21—Cash Flow Information
Millions of Dollars
2019
2018
2017
Noncash Investing Activities
Increase (decrease) in PP&E related to an increase (decrease)
 
in asset
retirement obligations
$
205
395
(37)
Increase (decrease) in assets and liabilities acquired in
 
a nonmonetary
exchange*
Accounts receivable
-
(44)
-
Inventories
-
42
-
Investments and long-term receivables
-
15
-
PP&E
-
1,907
-
Other long-term assets
-
(9)
-
Accounts payable
-
7
-
Accrued income and other taxes
-
40
-
Cash Payments
Interest
$
810
772
1,163
Income taxes
2,905
2,976
1,168
Net Sales (Purchases) of Investments
Short-term investments purchased
$
(4,902)
(1,953)
(6,617)
Short-term investments sold
2,138
3,573
4,827
Investments and long-term receivables purchased
(146)
-
-
$
(2,910)
1,620
(1,790)
*See Note 5—Asset Acquisitions and
 
Dispositions.
 
 
The following items are included in the “Cash Flows from
 
Operating Activities” section of our consolidated
cash flows.
 
We
 
collected $
330
 
million and $
430
 
million in 2019 and 2018, respectively, from PDVSA under
 
a settlement
agreement related to an award issued by the ICC
 
Tribunal in 2018.
 
We collected $
262
 
million and $
75
 
million
from Ecuador in 2018 and 2017, respectively,
 
as installment payments related to an agreement
 
reached with
Ecuador in 2017.
 
For more information on these settlements,
 
see Note 13—Contingencies and Commitments.
 
In 2019, we made a $
324
 
million contribution to our U.K.
 
pension plan.
 
We
 
made discretionary payments to
our domestic qualified pension plan of $
120
 
million and $
600
 
million in 2018 and 2017, respectively.
 
In 2017, we recognized a $
180
 
million adverse cash impact from the settlement
 
of cross-currency swap
transactions.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
130
 
Note 22—Other Financial Information
Millions of Dollars
2019
2018
2017
Interest and Debt Expense
Incurred
Debt
$
799
838
1,114
Other
36
67
103
835
905
1,217
Capitalized
(57)
(170)
(119)
Expensed
$
778
735
1,098
Other Income
Interest income
$
166
97
112
Unrealized gains (losses) on Cenovus Energy common shares*
649
(437)
-
Other, net
543
513
417
$
1,358
173
529
*See Note 7—Investment
 
in Cenovus Energy,
 
for additional information.
Research and Development Expenditures
—expensed
$
82
78
100
Shipping and Handling Costs
$
1,008
1,075
1,050
Foreign Currency Transaction (Gains) Losses
—after-tax
Alaska
$
-
-
-
Lower 48
-
-
-
Canada
5
(11)
3
Europe, Middle East and North Africa
-
(26)
7
Asia Pacific
31
3
23
Other International
1
-
1
Corporate and Other
21
21
(3)
$
58
(13)
31
 
 
Millions of Dollars
2019
2018
Properties, Plants and Equipment
Proved properties
$
88,284
*
100,657
Unproved properties
3,980
*
4,662
Other
5,482
5,278
Gross properties, plants and equipment
97,746
110,597
Less: Accumulated depreciation, depletion and amortization
(55,477)
*
(64,899)
Net properties, plants and equipment
$
42,269
45,698
*Excludes assets classified
 
as held for sale at December
 
31, 2019.
 
See Note 5
—
Asset Acquisitions and Dispositions,
 
for additional information.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
131
 
Note 23—Related Party Transactions
Our related parties primarily include equity method
 
investments and certain trusts for the benefit of
 
employees.
Significant transactions with our equity affiliates were:
 
Millions of Dollars
2019
2018
2017
Operating revenues and other income
$
89
98
107
Purchases
38
98
99
Operating expenses and selling, general and administrative
 
expenses
65
60
59
Net interest (income) expense*
(13)
(14)
(13)
*We
 
paid interest to, or received
 
interest from, various
 
affiliates.
 
See Note 6—Investments,
 
Loans and Long-Term
 
Receivables, for additional
 
information on loans to
 
affiliated companies.
 
 
The table above includes transactions with the FCCL
 
Partnership through the date of the sale.
 
See Note 6—
Investments, Loans and Long-Term Receivables, for additional information.
 
 
Note 24—Sales and Other Operating Revenues
 
 
Revenue from Contracts with Customers
 
The following table provides further disaggregation
 
of our consolidated sales and other operating revenues:
 
 
 
Millions of Dollars
2019
2018
2017
Revenue from contracts with customers
$
26,106
28,098
20,525
Revenue from contracts outside the scope of ASC
 
Topic 606
Physical contracts meeting the definition of a derivative
6,558
8,218
8,669
Financial derivative contracts
(97)
101
(88)
Consolidated sales and other operating revenues
$
32,567
36,417
29,106
 
Revenues from contracts outside the scope of ASC
 
Topic 606 relate primarily to physical gas contracts at
market prices which qualify as derivatives accounted
 
for under ASC Topic 815, “Derivatives and Hedging,”
and for which we have not elected NPNS.
 
There is no significant difference in contractual terms
 
or the policy
for recognition of revenue from these contracts
 
and those within the scope of ASC Topic 606.
 
The following
disaggregation of revenues is provided in conjunction
 
with Note 25—Segment Disclosures and Related
Information:
 
 
Millions of Dollars
2019
2018
2017
Revenue from Outside the Scope of ASC Topic 606
by Segment
Lower 48
$
4,989
6,358
6,302
Canada
691
629
864
Europe, Middle East and North Africa
878
1,231
1,503
Physical contracts meeting the definition of a derivative
$
6,558
8,218
8,669
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
132
 
Millions of Dollars
2019
2018
2017
Revenue from Outside the Scope of ASC Topic 606
by Product
Crude oil
$
804
1,112
588
Natural gas
5,313
6,734
7,811
Other
441
372
270
Physical contracts meeting the definition of a derivative
$
6,558
8,218
8,669
 
Practical Expedients
 
Typically,
 
our commodity sales contracts are less than 12 months
 
in duration; however, in certain specific
cases may extend longer, which may be out to the end of field
 
life.
 
We have long-term commodity sales
contracts which use prevailing market prices at the time of delivery, and under these contracts, the market-
based variable consideration for each performance obligation (i.e., delivery of commodity) is allocated to each
wholly unsatisfied performance obligation within the contract.
 
Accordingly, we have
applied
 
the practical
expedient allowed in ASC Topic 606 and do not disclose the aggregate amount of the
 
transaction price
allocated to performance obligations or when we expect
 
to recognize revenues that are unsatisfied
 
(or partially
unsatisfied) as of the end of the reporting period.
 
 
Receivables and Contract Liabilities
 
 
Receivables from Contracts with Customers
At December 31, 2019, the “Accounts and notes receivable”
 
line on our consolidated balance sheet
 
included
trade receivables of $
2,372
 
million compared with $
2,889
 
million at December 31, 2018, and included both
contracts with customers within the scope of ASC Topic 606 and those that are outside
 
the scope of ASC
Topic 606.
 
We typically receive payment within 30 days or less (depending on the terms of the invoice) once
delivery is made.
 
Revenues that are outside the scope of
 
ASC Topic 606 relate primarily to physical gas sales
contracts at market prices for which we do not elect
 
NPNS and are therefore accounted for as a derivative
under ASC Topic 815.
 
There is little distinction in the nature of the customer
 
or credit quality of trade
receivables associated with gas sold under contracts
 
for which NPNS has not been elected compared
 
with trade
receivables where NPNS has been elected.
 
 
Contract Liabilities from Contracts with Customers
We have entered into contractual arrangements where we license proprietary technology to customers related
to the optimization process for operating LNG plants. The agreements typically provide for negotiated
payments to be made at stated milestones. The payments are not directly related to our performance under the
contract and are recorded as deferred revenue to be recognized as revenue when the customer can utilize and
benefit from their right to use the license. Payments are received in installments over the construction period.
 
 
 
Millions of
Dollars
Contract Liabilities
At December 31, 2018
$
206
Contractual payments received
73
Revenue recognized
(199)
At December 31, 2019
$
80
 
We expect to recognize the contract liabilities as of December 31, 2019, as revenue during 2021 and 2022.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
133
 
Note 25—Segment Disclosures and Related Information
 
We
 
explore for, produce, transport and market crude oil, bitumen,
 
natural gas, LNG and NGLs on a worldwide
basis.
 
We manage our operations through
six
 
operating segments, which are primarily defined
 
by geographic
region: Alaska; Lower 48; Canada;
 
Europe, Middle East and North Africa; Asia Pacific
 
and Other
International.
 
Corporate and Other represents costs not directly
 
associated with an operating segment, such as
 
most interest
expense, premiums on early retirement of debt, corporate
 
overhead and certain technology activities, including
licensing revenues.
 
Corporate assets include all cash and cash equivalents
 
and short-term investments.
 
 
We
 
evaluate performance and allocate resources
 
based on net income (loss) attributable to ConocoPhillips.
 
Segment accounting policies are the same as those
 
in Note 1—Accounting Policies.
 
Intersegment sales are at
prices that approximate market.
 
Effective with the third quarter of 2020, we have restructured
 
our segments to align with the changes to our
internal organization.
 
The Middle East business was realigned
 
from the Asia Pacific and Middle East
 
segment
to the Europe and North Africa segment.
 
The segments have been renamed the
 
Asia Pacific segment and the
Europe, Middle East and North Africa segment.
 
We
 
have revised segment information
 
disclosures and
segment performance metrics presented within
 
our results of operations for the current and prior
 
years.
 
 
Analysis of Results by Operating Segment
Millions of Dollars
2019
**
2018
**
2017
**
Sales and Other Operating Revenues
Alaska
$
5,483
5,740
4,224
Lower 48
15,514
17,029
12,968
Intersegment eliminations
(46)
(40)
(4)
Lower 48
15,468
16,989
12,964
Canada
2,910
3,184
3,178
Intersegment eliminations
(1,141)
(1,160)
(559)
Canada
1,769
2,024
2,619
Europe, Middle East and North Africa
5,101
6,635
5,181
Asia Pacific
4,525
4,861
4,014
Other International
-
-
-
Corporate and Other
221
168
104
Consolidated sales and other operating revenues
$
32,567
36,417
29,106
 
Depreciation, Depletion, Amortization and Impairments
Alaska
$
805
760
1,026
Lower 48
3,224
2,370
6,693
Canada
232
324
461
Europe, Middle East and North Africa
887
1,041
1,313
Asia Pacific
1,285
1,382
3,819
Other International
-
-
-
Corporate and Other
62
106
134
Consolidated depreciation, depletion, amortization
 
and impairments
$
6,495
5,983
13,446
The market for our products is large and diverse, therefore,
 
our sales and other operating revenues are not
dependent upon any single customer.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
134
 
Millions of Dollars
2019
**
2018
**
2017
**
Equity in Earnings of Affiliates
Alaska
$
7
6
7
Lower 48
(159)
1
5
Canada
-
-
197
Europe, Middle East and North Africa
470
744
534
Asia Pacific
461
323
29
Other International
-
-
-
Corporate and Other
-
-
-
Consolidated equity in earnings of affiliates
$
779
1,074
772
 
Income Taxes
Alaska
$
472
376
(689)
Lower 48
137
474
(2,453)
Canada
(43)
(96)
(616)
Europe, Middle East and North Africa
1,425
2,259
1,120
Asia Pacific
501
728
396
Other International
8
30
21
Corporate and Other
(233)
(103)
399
Consolidated income taxes
$
2,267
3,668
(1,822)
 
Net Income (Loss) Attributable to ConocoPhillips
Alaska
$
1,520
1,814
1,466
Lower 48
436
1,747
(2,371)
Canada
279
63
2,564
Europe, Middle East and North Africa
3,170
2,594
1,116
Asia Pacific
1,483
1,342
(1,661)
Other International
263
364
167
Corporate and Other
38
(1,667)
(2,136)
Consolidated net income (loss) attributable to ConocoPhillips
$
7,189
6,257
(855)
 
Investments in and Advances to Affiliates
Alaska
$
83
86
56
Lower 48
35
378
402
Canada
-
-
-
Europe, Middle East and North Africa
1,070
1,311
1,402
Asia Pacific
7,265
7,565
7,730
Other International
-
-
-
Corporate and Other
-
-
-
Consolidated investments in and advances to affiliates
$
8,453
9,340
9,590
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
135
 
Millions of Dollars
2019
**
2018
**
2017
**
Total Assets
Alaska
$
15,453
14,648
12,108
Lower 48
14,425
14,888
14,632
Canada
6,350
5,748
6,214
Europe, Middle East and North Africa
9,269
11,276
13,346
Asia Pacific
13,568
14,758
15,509
Other International
285
89
97
Corporate and Other
11,164
8,573
11,456
Consolidated total assets
$
70,514
69,980
73,362
 
Capital Expenditures and Investments
Alaska
$
1,513
1,298
815
Lower 48
3,394
3,184
2,136
Canada
368
477
202
Europe, Middle East and North Africa
708
877
872
Asia Pacific
584
718
482
Other International
8
6
21
Corporate and Other
61
190
63
Consolidated capital expenditures and investments
$
6,636
6,750
4,591
 
Interest Income and Expense
Interest income
Alaska
$
-
-
-
Lower 48
-
-
-
Canada
-
-
-
Europe, Middle East and North Africa
11
12
11
Asia Pacific
6
5
-
Other International
-
-
-
Corporate and Other
149
80
101
Interest and debt expense
Corporate and Other
$
778
735
1,098
 
Sales and Other Operating Revenues by Product
Crude oil
$
18,482
19,571
13,260
Natural gas
8,715
10,720
10,773
Natural gas liquids
814
1,114
1,102
Other*
4,556
5,012
3,971
Consolidated sales and other operating revenues
 
by product
$
32,567
36,417
29,106
*Includes LNG and bitumen.
**Prior periods have been updated
 
to reflect the Middle East Business
 
Unit moving from
 
Asia Pacific to the Europe,
 
Middle East
 
and North
Africa segment.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
136
 
Geographic Information
Millions of Dollars
Sales and Other Operating Revenues
(1)
Long-Lived Assets
(2)
2019
2018
2017
2019
2018
2017
United States
(3)
$
21,159
22,740
17,204
26,566
26,838
23,623
Australia and Timor-Leste
(4)
1,647
1,798
1,448
7,228
9,301
9,657
Canada
1,769
2,024
2,619
5,769
5,333
5,613
China
772
836
712
1,447
1,380
1,275
Indonesia
875
886
757
605
669
758
Libya
1,103
1,142
586
668
679
699
Malaysia
1,230
1,346
1,103
1,871
2,327
2,736
Norway
2,349
2,886
2,348
5,258
5,582
6,154
United Kingdom
1,649
2,606
2,248
2
1,583
3,335
Other foreign countries
14
153
81
1,308
1,346
1,423
Worldwide consolidated
$
32,567
36,417
29,106
50,722
55,038
55,273
(1)
Sales and other operating revenues
 
are attributable to countries based
 
on the location of the selling operation.
(2)
Defined as net PP&E plus
 
equity investments and advances
 
to affiliated companies.
(3)
Long-lived assets do not include $
426
 
million of net PP&E associated with
 
assets held for sale as of December
 
31,
2019.
 
See Note 5—Acquisitions and
 
Dispositions, for additional information.
(4)
Long-lived assets do not include $
1,236
 
million of net PP&E associated
 
with assets held for sale as
 
of December
31, 2019.
 
See Note 5—Acquisitions and
 
Dispositions, for additional information.
 
 
 
Note 26—New Accounting Standards
 
 
In June 2016, the FASB issued ASU No. 2016-13, “Measurement of Credit Losses on Financial
 
Instruments”
(ASU No. 2016-13), which sets forth the current expected
 
credit loss model, a new forward-looking
impairment model for certain financial instruments based
 
on expected losses rather than incurred losses.
 
The
ASU is effective for interim and annual periods beginning
 
after December 15, 2019.
 
Entities are required to
adopt ASU No. 2016-13 using a modified retrospective
 
approach, subject to certain limited exceptions.
 
The
impact of adopting this ASU is not expected to be
 
material to our financial statements.
 
 
 
 
137
 
Oil and Gas Operations
(Unaudited)
 
 
 
 
In accordance with FASB ASC Topic 932, “Extractive Activities—Oil and Gas,” and regulations of the SEC,
we are making certain supplemental disclosures about
 
our oil and gas exploration and production
 
operations.
 
 
These disclosures include information about our
 
consolidated oil and gas activities and our proportionate
 
share
of our equity affiliates’ oil and gas activities in our operating
 
segments.
 
As a result, amounts reported as
equity affiliates in Oil and Gas Operations may differ from
 
those shown in the individual segment disclosures
reported elsewhere in this report. Our disclosures by geographic
 
area include the U.S., Canada, Europe, Asia
Pacific/Middle East, and Africa. Period end proved
 
reserves, capitalized costs, wells and acreage
 
include held-
for-sale assets at December 31, 2019. See Note 5—Asset
 
Acquisitions and Dispositions, in the Notes to
Consolidated Financial Statements, for additional
 
information on held-for-sale assets.
 
 
As required by current authoritative guidelines,
 
the estimated future date when an asset will
 
be permanently
shut down for economic reasons is based on historical
 
12-month first-of-month average prices and
 
current
costs.
 
This estimated date when production will
 
end affects the amount of estimated reserves.
 
Therefore, as
prices and cost levels change from year to year, the estimate
 
of proved reserves also changes.
 
Generally, our
proved reserves decrease as prices decline and increase
 
as prices rise.
 
 
Our proved reserves include estimated quantities related
 
to PSCs, which are reported under the
 
“economic
interest” method, as well as variable-royalty regimes, and
 
are subject to fluctuations in commodity prices,
recoverable operating expenses and capital costs.
 
If costs remain stable, reserve quantities
 
attributable to
recovery of costs will change inversely to changes in commodity
 
prices.
 
For example, if prices increase, then
our applicable reserve quantities would decline.
 
At December 31, 2019, approximately 6 percent
 
of our total
proved reserves were under PSCs, located in our
 
Asia Pacific/Middle East geographic reporting area,
 
and 6
percent of our total proved reserves were under a
 
variable-royalty regime, located in our Canada
 
geographic
reporting area.
 
Reserves Governance
 
The recording and reporting of proved reserves are
 
governed by criteria established by regulations
 
of the SEC
and FASB.
 
Proved reserves are those quantities of oil
 
and gas, which, by analysis of geoscience and
engineering data, can be estimated with reasonable
 
certainty to be economically producible—from
 
a given date
forward, from known reservoirs, and under existing economic
 
conditions, operating methods, and government
regulations—prior to the time at which contracts providing
 
the right to operate expire, unless evidence
indicates renewal is reasonably certain, regardless
 
of whether deterministic or probabilistic methods
 
are used
for the estimation.
 
The project to extract the hydrocarbons
 
must have commenced or the operator must be
reasonably certain it will commence the project within
 
a reasonable time.
 
 
Proved reserves are further classified as either
 
developed or undeveloped.
 
Proved developed reserves are
proved reserves that can be expected to be recovered
 
through existing wells with existing
 
equipment and
operating methods, or in which the cost of the required
 
equipment is relatively minor compared with the cost
of a new well, and through installed extraction equipment
 
and infrastructure operational at the time of the
reserves estimate if the extraction is by means not
 
involving a well.
 
Proved undeveloped reserves are proved
reserves expected to be recovered from new wells
 
on undrilled acreage, or from existing wells
 
where a
relatively major expenditure is required for recompletion.
 
Reserves on undrilled acreage are limited to those
directly offsetting development spacing areas that are reasonably
 
certain of production when drilled, unless
evidence provided by reliable technologies exists
 
that establishes reasonable certainty of economic
producibility at greater distances. As defined by
 
SEC regulations, reliable technologies may
 
be used in reserve
estimation when they have been demonstrated in the
 
field to provide reasonably certain results
 
with
consistency and repeatability in the formation
 
being evaluated or in an analogous formation.
 
The technologies
and data used in the estimation of our proved reserves include,
 
but are not limited to, performance-based
 
138
 
methods, volumetric-based methods, geologic maps, seismic
 
interpretation, well logs, well test data, core data,
analogy and statistical analysis.
 
We
 
have a companywide, comprehensive,
 
SEC-compliant internal policy that governs the
 
determination and
reporting of proved reserves.
 
This policy is applied by the geoscientists
 
and reservoir engineers in our
business units around the world.
 
As part of our internal control process, each business
 
unit’s reserves
processes and controls are reviewed annually by
 
an internal team which is headed by the company’s Manager
of Reserves Compliance and Reporting.
 
This team, composed of internal reservoir
 
engineers, geoscientists,
finance personnel and a senior representative from DeGolyer
 
and MacNaughton (D&M), a third-party
petroleum engineering consulting firm, reviews the
 
business units’ reserves for adherence to SEC guidelines
and company policy through on-site visits, teleconferences
 
and review of documentation.
 
In addition to
providing independent reviews, this internal team
 
also ensures reserves are calculated using
 
consistent and
appropriate standards and procedures.
 
This team is independent of business unit
 
line management and is
responsible for reporting its findings to senior management.
 
The team is responsible for communicating our
reserves policy and procedures and is available
 
for internal peer reviews and consultation on major
 
projects or
technical issues throughout the year.
 
All of our proved reserves held by consolidated
 
companies and our share
of equity affiliates have been estimated by ConocoPhillips.
 
During 2019, our processes and controls used to assess
 
over 90 percent of proved reserves as of December
 
31,
2019, were reviewed by D&M.
 
The purpose of their review was to assess whether
 
the adequacy and
effectiveness of our internal processes and controls used to
 
determine estimates of proved reserves are in
accordance with SEC regulations.
 
In such review, ConocoPhillips’ technical staff presented D&M with an
overview of the reserves data, as well as the methods
 
and assumptions used in estimating reserves.
 
The data
presented included pertinent seismic information,
 
geologic maps, well logs, production tests,
 
material balance
calculations, reservoir simulation models, well performance
 
data, operating procedures and relevant
 
economic
criteria.
 
Management’s intent in retaining D&M to review its
 
processes and controls was to provide objective
third-party input on these processes and controls.
 
D&M’s opinion was the general processes and controls
employed by ConocoPhillips in estimating its December
 
31, 2019, proved reserves for the properties reviewed
are in accordance with the SEC reserves definitions.
 
D&M’s report is included as Exhibit 99.2 of this Current
Report on Form 8-K.
 
The technical person primarily responsible for overseeing
 
the processes and internal controls used in the
preparation of the company’s reserves estimates is the Manager of
 
Reserves Compliance and Reporting.
 
This
individual holds a master’s degree in petroleum engineering.
 
He is a member of the Society of Petroleum
Engineers with over 25 years of oil and gas industry
 
experience and has held positions of increasing
responsibility in reservoir engineering, subsurface and asset
 
management in the U.S.
 
and several international
field locations.
 
 
Engineering estimates of the quantities of proved reserves
 
are inherently imprecise.
 
See the “Critical
Accounting Estimates” section of Management’s Discussion and Analysis of
 
Financial Condition and Results
of Operations for additional discussion of the sensitivities
 
surrounding these estimates.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
139
 
Proved Reserves
Years Ended
Crude Oil
December 31
Millions of Barrels
Lower
Total
Asia Pacific/
Alaska
48
U.S.
Canada
Europe
Middle East
Africa
Total
Developed and Undeveloped
Consolidated operations
End of 2016
837
506
1,343
13
303
185
203
2,047
Revisions
113
65
178
1
38
32
-
249
Improved recovery
6
-
6
-
-
-
-
6
Purchases
-
-
-
-
-
-
-
-
Extensions and discoveries
41
210
251
-
-
2
-
253
Production
(60)
(64)
(124)
(1)
(45)
(34)
(7)
(211)
Sales
-
(10)
(10)
(12)
-
-
-
(22)
End of 2017
937
707
1,644
1
296
185
196
2,322
Revisions
72
(90)
(18)
2
24
6
5
19
Improved recovery
2
-
2
-
-
-
-
2
Purchases
233
1
234
-
-
-
-
234
Extensions and discoveries
48
179
227
2
2
1
-
232
Production
(59)
(82)
(141)
(1)
(40)
(33)
(13)
(228)
Sales
-
(12)
(12)
-
(36)
-
-
(48)
End of 2018
1,233
703
1,936
4
246
159
188
2,533
Revisions
40
(36)
4
(1)
18
(5)
23
39
Improved recovery
7
-
7
-
-
-
-
7
Purchases
-
1
1
-
-
-
-
1
Extensions and discoveries
25
226
251
2
-
11
-
264
Production
(74)
(95)
(169)
-
(36)
(31)
(14)
(250)
Sales
-
(2)
(2)
-
(30)
-
-
(32)
End of 2019
1,231
797
2,028
5
198
134
197
2,562
Equity affiliates
End of 2016
-
 
-
-
-
-
 
88
-
 
88
Revisions
-
-
-
-
-
-
-
-
Improved recovery
-
-
-
-
-
-
-
-
Purchases
-
-
-
-
-
-
-
-
Extensions and discoveries
-
-
-
-
-
-
-
-
Production
-
-
-
-
-
(5)
-
(5)
Sales
-
-
-
-
-
-
-
-
End of 2017
-
-
-
-
-
83
-
83
Revisions
-
-
-
-
-
-
-
-
Improved recovery
-
-
-
-
-
-
-
-
Purchases
-
-
-
-
-
-
-
-
Extensions and discoveries
-
-
-
-
-
-
-
-
Production
-
-
-
-
-
(5)
-
(5)
Sales
-
-
-
-
-
-
-
-
End of 2018
-
-
-
-
-
78
-
78
Revisions
-
-
-
-
-
-
-
-
Improved recovery
-
-
-
-
-
-
-
-
Purchases
-
-
-
-
-
-
-
-
Extensions and discoveries
-
-
-
-
-
-
-
-
Production
-
-
-
-
-
(5)
-
(5)
Sales
-
-
-
-
-
-
-
-
End of 2019
-
-
-
-
-
73
-
73
Total company
End of 2016
837
506
1,343
13
303
273
203
2,135
End of 2017
937
707
1,644
1
296
268
196
2,405
End of 2018
1,233
703
1,936
4
246
237
188
2,611
End of 2019
1,231
797
2,028
5
198
207
197
2,635
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
140
 
Years Ended
Crude Oil
December 31
Millions of Barrels
Lower
Total
Asia Pacific/
Alaska
48
U.S.
Canada
Europe
Middle East
Africa
Total
Developed
Consolidated operations
End of 2016
747
256
1,003
13
184
106
203
1,509
End of 2017
828
315
1,143
1
190
121
196
1,651
End of 2018
1,058
346
1,404
2
192
113
185
1,896
End of 2019
1,048
334
1,382
3
149
94
181
1,809
Equity affiliates
End of 2016
-
-
-
-
-
88
-
88
End of 2017
-
-
-
-
-
83
-
83
End of 2018
-
-
-
-
-
78
-
78
End of 2019
-
-
-
-
-
73
-
73
Undeveloped
Consolidated operations
End of 2016
90
250
340
-
119
79
-
538
End of 2017
109
392
501
-
106
64
-
671
End of 2018
175
357
532
2
54
46
3
637
End of 2019
183
463
646
2
49
40
16
753
Equity affiliates
End of 2016
-
-
-
-
-
-
-
-
End of 2017
-
-
-
-
-
-
-
-
End of 2018
-
-
-
-
-
-
-
-
End of 2019
-
-
-
-
-
-
-
-
 
 
Notable changes in proved crude oil reserves in the
 
three years ended December 31, 2019,
 
included:
 
●
 
Revisions
: In 2019, Alaska upward revisions were
 
due to cost and technical revisions of 74
 
million barrels, partially
offset by downward price revisions of 34 million barrels.
 
Upward revisions in Europe and Africa were primarily
 
due to
infill drilling and technical revisions.
 
Downward revisions in Lower 48 were due to changes
 
in development timing for
specific well locations from the unconventional plays
 
of 71 million barrels and price revisions of 22 million
 
barrels,
partially offset by upward revisions related to infill drilling
 
and improved well performance of 57 million barrels.
 
 
In 2018, downward revisions in Lower 48 were primarily
 
due to changes in development timing for specific well
locations from the unconventional plays and are more
 
than offset by increases in planned well locations in the
unconventional plays in the extensions and discoveries
 
category.
 
Downward revisions in Lower 48 due to
 
development
timing were partially offset by higher prices. Revisions
 
in Alaska, Europe and Asia Pacific/Middle East were
 
primarily
due to higher prices.
 
 
In 2017, revisions in Alaska, Lower 48, Europe and
 
Asia Pacific/Middle East were primarily due to
 
higher prices.
 
●
 
Purchases:
 
In 2018, Alaska purchases were due
 
to the Greater Kuparuk Area and Western North Slope acquisitions.
 
 
 
 
 
141
 
●
 
Extensions and discoveries
: In 2019, extensions and discoveries in
 
Lower 48 were due to planned development
 
to add
specific well locations from the unconventional plays
 
which more than offset the decreases in the revisions
 
category.
 
In Asia Pacific/Middle East, increases were due to sanctioning
 
of development programs in China and Malaysia.
 
In 2018, extensions and discoveries in Lower 48 were
 
primarily due to changes in the
 
development strategy to add
specific well locations from the unconventional plays.
 
Extensions and discoveries in Alaska were
 
driven by drilling
success in Western North Slope.
 
In 2017, extensions and discoveries in Lower 48 were
 
primarily due to continued drilling
 
success in the Permian
Unconventional, Eagle Ford and Bakken.
 
 
●
 
Sales
: In 2019, Europe sales represent the disposition
 
of the U.K. assets. In 2018, Europe
 
sales were due to the
disposition of a subsidiary that held 16.5 percent of our
 
24 percent interest in the Clair Field in the
 
U.K.
 
In 2017,
Canada sales were due to the disposition of a majority
 
of our western Canada assets.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
142
 
Years Ended
Natural Gas Liquids
December 31
Millions of Barrels
Lower
Total
Asia Pacific/
Alaska
48
U.S.
Canada
Europe
Middle East
Total
Developed and Undeveloped
Consolidated operations
End of 2016
107
278
385
48
19
5
457
Revisions
4
29
33
-
2
1
36
Improved recovery
-
-
-
-
-
-
-
Purchases
-
-
-
-
-
-
-
Extensions and discoveries
-
71
71
-
-
1
72
Production
(5)
(24)
(29)
(3)
(3)
(2)
(37)
Sales
-
(130)
(130)
(44)
-
-
(174)
End of 2017
106
224
330
1
18
5
354
Revisions
5
(25)
(20)
-
1
(1)
(20)
Improved recovery
-
-
-
-
-
-
-
Purchases
-
-
-
-
-
-
-
Extensions and discoveries
-
69
69
-
1
-
70
Production
(5)
(25)
(30)
-
(3)
(1)
(34)
Sales
-
(21)
(21)
-
-
-
(21)
End of 2018
106
222
328
1
17
3
349
Revisions
(1)
(11)
(12)
-
3
(1)
(10)
Improved recovery
-
-
-
-
-
-
-
Purchases
-
-
-
-
-
-
-
Extensions and discoveries
-
62
62
1
-
-
63
Production
(5)
(28)
(33)
-
(3)
(1)
(37)
Sales
-
-
-
-
(4)
-
(4)
End of 2019
100
245
345
2
13
1
361
Equity affiliates
End of 2016
-
 
-
-
-
-
 
47
47
Revisions
-
-
-
-
-
-
-
Improved recovery
-
-
-
-
-
-
-
Purchases
-
-
-
-
-
-
-
Extensions and discoveries
-
-
-
-
-
-
-
Production
-
-
-
-
-
(2)
(2)
Sales
-
-
-
-
-
-
-
End of 2017
-
-
-
-
-
45
45
Revisions
-
-
-
-
-
-
-
Improved recovery
-
-
-
-
-
-
-
Purchases
-
-
-
-
-
-
-
Extensions and discoveries
-
-
-
-
-
-
-
Production
-
-
-
-
-
(3)
(3)
Sales
-
-
-
-
-
-
-
End of 2018
-
-
-
-
-
42
42
Revisions
-
-
-
-
-
-
-
Improved recovery
-
-
-
-
-
-
-
Purchases
-
-
-
-
-
-
-
Extensions and discoveries
-
-
-
-
-
-
-
Production
-
-
-
-
-
(3)
(3)
Sales
-
-
-
-
-
-
-
End of 2019
-
-
-
-
-
39
39
Total company
End of 2016
107
278
385
48
19
52
504
End of 2017
106
224
330
1
18
50
399
End of 2018
106
222
328
1
17
45
391
End of 2019
100
245
345
2
13
40
400
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
143
 
Years Ended
Natural Gas Liquids
December 31
Millions of Barrels
Lower
Total
Asia Pacific/
Alaska
48
U.S.
Canada
Europe
Middle East
Total
Developed
Consolidated operations
End of 2016
107
209
316
47
15
5
383
End of 2017
106
101
207
1
16
2
226
End of 2018
106
97
203
-
15
3
221
End of 2019
100
99
199
1
10
1
211
Equity affiliates
End of 2016
-
-
-
-
-
47
47
End of 2017
-
-
-
-
-
45
45
End of 2018
-
-
-
-
-
42
42
End of 2019
-
-
-
-
-
39
39
Undeveloped
Consolidated operations
End of 2016
-
69
69
1
4
-
74
End of 2017
-
123
123
-
2
3
128
End of 2018
-
125
125
1
2
-
128
End of 2019
-
146
146
1
3
-
150
Equity affiliates
End of 2016
-
-
-
-
-
-
-
End of 2017
-
-
-
-
-
-
-
End of 2018
-
-
-
-
-
-
-
End of 2019
-
-
-
-
-
-
-
 
 
Notable changes in proved NGL reserves in the three
 
years ended December
 
31, 2019, included:
 
●
 
Revisions
: In 2019, downward revisions in Lower
 
48 were due to changes in development timing
 
for specific well
locations from the unconventional plays of 32 million
 
barrels and price revisions of 11 million barrels, partially offset
by upward revisions related to infill drilling and
 
improved well performance of 32 million barrels.
 
In 2018, downward revisions in Lower 48 were primarily
 
due to changes in development timing for specific well
locations from the unconventional plays and are more
 
than offset by increases in planned well locations in the
unconventional plays in the extensions and discoveries
 
category.
 
 
In 2017, revisions in Lower 48 were primarily due
 
to higher prices.
 
●
 
Extensions and discoveries
: In 2019, extensions and discoveries in
 
Lower 48 were due to planned development
 
to add
specific well locations from the unconventional plays
 
which more than offset the decreases in the revisions
 
category.
 
In 2018, extensions and discoveries in Lower 48 were
 
primarily due to changes in the
 
development strategy to add
specific well locations from the unconventional plays.
 
 
In 2017, extensions and discoveries in Lower 48 were
 
primarily due to continued drilling
 
success in the Permian
Unconventional, Eagle Ford and Bakken.
 
●
 
Sales
: In 2019, Europe sales represent the disposition
 
of the U.K. assets.
 
In 2018, Lower 48 sales were primarily
 
due to
the disposition of our interests in the Barnett.
 
In 2017, Lower 48 sales were due to the disposition
 
of our interests in the
San Juan Basin and Panhandle assets, while Canada sales
 
were due to the disposition of a majority of our western
Canada assets.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
144
 
Years Ended
Natural Gas
December 31
Billions of Cubic Feet
Lower
Total
Asia Pacific/
Alaska
48
U.S.
Canada
Europe
Middle East
Africa
Total
Developed and Undeveloped
Consolidated operations
End of 2016
2,102
4,714
6,816
1,037
1,238
1,526
227
10,844
Revisions
287
460
747
8
167
16
-
938
Improved recovery
-
-
-
-
-
-
-
-
Purchases
-
-
-
-
-
-
-
-
Extensions and discoveries
2
582
584
3
-
23
-
610
Production
(71)
(338)
(409)
(71)
(188)
(267)
(3)
(938)
Sales
-
(2,885)
(2,885)
(966)
-
-
-
(3,851)
End of 2017
2,320
2,533
4,853
11
1,217
1,298
224
7,603
Revisions
150
(283)
(133)
9
86
4
-
(34)
Improved recovery
-
-
-
-
-
-
-
-
Purchases
335
1
336
-
-
-
-
336
Extensions and discoveries
2
527
529
11
110
23
-
673
Production
(71)
(237)
(308)
(5)
(188)
(246)
(10)
(757)
Sales
-
(223)
(223)
-
(13)
-
-
(236)
End of 2018
2,736
2,318
5,054
26
1,212
1,079
214
7,585
Revisions
30
(113)
(83)
(2)
160
147
21
243
Improved recovery
-
-
-
-
-
-
-
-
Purchases
-
2
2
-
-
-
-
2
Extensions and discoveries
7
483
490
23
-
1
-
514
Production
(85)
(252)
(337)
(4)
(178)
(250)
(11)
(780)
Sales
-
(7)
(7)
-
(298)
-
-
(305)
End of 2019
2,688
2,431
5,119
43
896
977
224
7,259
Equity affiliates
End of 2016
-
-
-
-
-
4,381
-
4,381
Revisions
-
-
-
-
-
111
-
111
Improved recovery
-
-
-
-
-
-
-
-
Purchases
-
-
-
-
-
-
-
-
Extensions and discoveries
-
-
-
-
-
185
-
185
Production
-
-
-
-
-
(374)
-
(374)
Sales
-
-
-
-
-
-
-
-
End of 2017
-
-
-
-
-
4,303
-
4,303
Revisions
-
-
-
-
-
280
-
280
Improved recovery
-
-
-
-
-
-
-
-
Purchases
-
-
-
-
-
-
-
-
Extensions and discoveries
-
-
-
-
-
362
-
362
Production
-
-
-
-
-
(381)
-
(381)
Sales
-
-
-
-
-
-
-
-
End of 2018
-
-
-
-
-
4,564
-
4,564
Revisions
-
-
-
-
-
(7)
-
(7)
Improved recovery
-
-
-
-
-
-
-
-
Purchases
-
-
-
-
-
-
-
-
Extensions and discoveries
-
-
-
-
-
252
-
252
Production
-
-
-
-
-
(388)
-
(388)
Sales
-
-
-
-
-
-
-
-
End of 2019
-
-
-
-
-
4,421
-
4,421
Total company
End of 2016
2,102
4,714
6,816
1,037
1,238
5,907
227
15,225
End of 2017
2,320
2,533
4,853
11
1,217
5,601
224
11,906
End of 2018
2,736
2,318
5,054
26
1,212
5,643
214
12,149
End of 2019
2,688
2,431
5,119
43
896
5,398
224
11,680
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
145
 
Years Ended
Natural Gas
December 31
Billions of Cubic Feet
Lower
Total
Asia Pacific/
Alaska
48
U.S.
Canada
Europe
Middle East
Africa
Total
Developed
Consolidated operations
End of 2016
2,094
4,199
6,293
1,031
998
1,188
227
9,737
End of 2017
2,310
1,597
3,907
11
997
945
224
6,084
End of 2018
2,720
1,427
4,147
17
1,052
758
214
6,188
End of 2019
2,601
1,398
3,999
30
697
843
224
5,793
Equity affiliates
End of 2016
-
-
-
-
-
4,110
-
4,110
End of 2017
-
-
-
-
-
4,044
-
4,044
End of 2018
-
-
-
-
-
4,059
-
4,059
End of 2019
-
-
-
-
-
3,898
-
3,898
Undeveloped
Consolidated operations
End of 2016
8
515
523
6
240
338
-
1,107
End of 2017
10
936
946
-
220
353
-
1,519
End of 2018
16
891
907
9
160
321
-
1,397
End of 2019
87
1,033
1,120
13
199
134
-
1,466
Equity affiliates
End of 2016
-
-
-
-
-
271
-
271
End of 2017
-
-
-
-
-
259
-
259
End of 2018
-
-
-
-
-
505
-
505
End of 2019
-
-
-
-
-
523
-
523
 
 
Natural gas production in the reserves table may differ from
 
gas production (delivered for sale) in our statistics
 
disclosure,
primarily because the quantities above include gas consumed
 
in production operations.
 
Quantities consumed in production
operations are not significant in the periods presented.
 
The value of net production consumed in
 
operations is not reflected in
net revenues and production expenses, nor do the
 
volumes impact the respective per unit metrics.
 
Reserve volumes include natural gas to be consumed
 
in operations of 3,141 Bcf,
 
3,131 Bcf,
 
and 3,825 Bcf as of December 31,
2019, 2018 and 2017, respectively.
 
These volumes are not included in the calculation
 
of our Standardized Measure of
Discounted Future Net Cash Flows Relating to Proved
 
Oil and Gas Reserve Quantities.
 
Natural gas reserves are computed at 14.65 pounds per
 
square inch absolute and 60 degrees Fahrenheit.
 
 
Notable changes in proved natural gas reserves
 
in the three years ended December 31, 2019, included:
 
●
 
Revisions
: In 2019, upward revisions in Europe were
 
due to technical and cost revisions.
 
In Asia Pacific/Middle East
upward revisions were primarily due to the Indonesia
 
Corridor PSC term extension.
 
Downward revisions in Lower 48
were due to changes in development
 
timing for specific well locations from
 
the unconventional plays of 207 Bcf and
price revisions of 125 Bcf, partially offset by upward revisions
 
related to infill drilling and improved well performance
of 219 Bcf.
 
In 2018, downward revisions in Lower 48 were primarily
 
due to changes in development timing for specific well
locations from the unconventional plays and are more
 
than offset by increases in planned well locations in the
unconventional plays in the extensions and discoveries
 
category.
 
Downward revisions in Lower 48 due to development
timing were partially offset by higher prices.
 
Revisions in Alaska, Canada, Europe and
 
our equity affiliates in Asia
Pacific/Middle East were primarily due to higher prices.
 
 
In 2017, revisions in Alaska, Lower 48 and Europe
 
were primarily due to higher prices.
 
 
 
 
146
 
 
●
 
Purchases
: In 2018, Alaska purchases were due to the
 
Greater Kuparuk Area and Western North Slope acquisitions.
 
●
 
Extensions and discoveries
: In 2019, extensions and discoveries in Lower
 
48 were due to planned development to add
specific well locations from the unconventional plays
 
which more than offset the decreases in the revisions
 
category.
 
Extensions and discoveries in our equity affiliates were due
 
to ongoing development in APLNG.
 
In 2018, extensions and discoveries in Lower 48 were
 
primarily due to changes in the
 
development strategy to add
specific well locations from the unconventional plays.
 
Extensions and discoveries in Canada, Europe
 
and our equity
affiliates in Asia Pacific/Middle East were primarily driven
 
by ongoing drilling successes in Montney, Norway and
APLNG,
 
respectively.
 
 
In 2017, extensions and discoveries in Lower 48 were
 
primarily due to continued drilling
 
success in the Permian
Unconventional, Eagle Ford and Bakken.
 
●
 
Sales
: In 2019, Europe sales represent the disposition
 
of the U.K. assets.
 
In 2018, Lower 48 sales were primarily
 
due to
the disposition of our interest in Barnett.
 
In 2017, Lower 48 sales were due to the disposition
 
of our interests in the San
Juan Basin and Panhandle assets, while Canada sales
 
were due to the disposition of a majority of our
 
western Canada
assets.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
147
 
Years Ended
Bitumen
December 31
Millions of Barrels
Canada
Developed and Undeveloped
Consolidated operations
End of 2016
159
Revisions
16
Improved recovery
-
Purchases
-
Extensions and discoveries
96
Production
(21)
Sales
-
End of 2017
250
Revisions
10
Improved recovery
-
Purchases
-
Extensions and discoveries
-
Production
(24)
Sales
-
End of 2018
236
Revisions
37
Improved recovery
-
Purchases
-
Extensions and discoveries
31
Production
(22)
Sales
-
End of 2019
282
Equity affiliates
End of 2016
1,089
Revisions
-
Improved recovery
-
Purchases
-
Extensions and discoveries
-
Production
(23)
Sales
(1,066)
End of 2017
-
Revisions
Improved recovery
Purchases
Extensions and discoveries
Production
Sales
End of 2018
Revisions
Improved recovery
Purchases
Extensions and discoveries
Production
Sales
End of 2019
Total company
End of 2016
1,248
End of 2017
250
End of 2018
236
End of 2019
282
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
148
 
Years Ended
Bitumen
December 31
Millions of Barrels
Canada
Developed
Consolidated operations
End of 2016
159
End of 2017
154
End of 2018
155
End of 2019
187
Equity affiliates
End of 2016
322
End of 2017
-
End of 2018
-
End of 2019
-
Undeveloped
Consolidated operations
End of 2016
-
End of 2017
96
End of 2018
81
End of 2019
95
Equity affiliates
End of 2016
767
End of 2017
-
End of 2018
-
End of 2019
-
 
 
Notable changes in proved bitumen reserves in the
 
three years ended December 31,
 
2019,
 
included:
 
 
●
 
Revisions
: In 2019, upward revisions in Canada were
 
due to technical revisions in Surmont of 70
million barrels, partially offset by downward revisions due
 
to changes in development timing for
specific pad locations from the Surmont development
 
program of 31 million
 
barrels.
 
In 2018 and 2017,
 
revisions were primarily due to higher prices
 
at Surmont.
 
●
 
Extensions and discoveries
: In 2019, extensions and discoveries in
 
Canada were due to planned
development to add specific pad locations from the
 
Surmont development program, which offset the
decrease in the revisions category of 31 million
 
barrels.
 
In 2017, extensions and discoveries were primarily due
 
to higher prices at Surmont, which allowed
undeveloped reserves previously de-booked due to low
 
prices to be recognized.
 
 
●
 
Sales
: In 2017, sales were due to the disposition
 
of our 50 percent interest in the FCCL Partnership
 
in
Canada.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
149
 
Years Ended
Total Proved Reserves
December 31
Millions of Barrels of Oil Equivalent
Lower
Total
Asia Pacific/
Alaska
48
U.S.
Canada
Europe
Middle East
Africa
Total
Developed and Undeveloped
Consolidated operations
End of 2016
1,294
1,570
2,864
393
528
444
241
4,470
Revisions
166
170
336
18
68
36
-
458
Improved recovery
6
-
6
-
-
-
-
6
Purchases
-
-
-
-
-
-
-
-
Extensions and discoveries
41
378
419
97
-
7
-
523
Production
(77)
(144)
(221)
(37)
(79)
(81)
(8)
(426)
Sales
-
(621)
(621)
(217)
-
-
-
(838)
End of 2017
1,430
1,353
2,783
254
517
406
233
4,193
Revisions
102
(161)
(59)
12
40
5
6
4
Improved recovery
2
-
2
-
-
-
-
2
Purchases
289
1
290
-
-
-
-
290
Extensions and discoveries
48
335
383
4
21
6
-
414
Production
(76)
(146)
(222)
(25)
(75)
(75)
(15)
(412)
Sales
-
(70)
(70)
-
(38)
-
-
(108)
End of 2018
1,795
1,312
3,107
245
465
342
224
4,383
Revisions
44
(67)
(23)
36
48
19
26
106
Improved recovery
7
-
7
-
-
-
-
7
Purchases
-
2
2
-
-
-
-
2
Extensions and discoveries
26
368
394
38
-
11
-
443
Production
(93)
(165)
(258)
(23)
(68)
(74)
(16)
(439)
Sales
-
(3)
(3)
-
(85)
-
-
(88)
End of 2019
1,779
1,447
3,226
296
360
298
234
4,414
Equity affiliates
End of 2016
-
-
-
1,089
-
865
-
1,954
Revisions
-
-
-
-
-
18
-
18
Improved recovery
-
-
-
-
-
-
-
-
Purchases
-
-
-
-
-
-
-
-
Extensions and discoveries
-
-
-
-
-
31
-
31
Production
-
-
-
(23)
-
(69)
-
(92)
Sales
-
-
-
(1,066)
-
-
-
(1,066)
End of 2017
-
-
-
-
-
845
-
845
Revisions
-
-
-
-
-
46
-
46
Improved recovery
-
-
-
-
-
-
-
-
Purchases
-
-
-
-
-
-
-
-
Extensions and discoveries
-
-
-
-
-
60
-
60
Production
-
-
-
-
-
(71)
-
(71)
Sales
-
-
-
-
-
-
-
-
End of 2018
-
-
-
-
-
880
-
880
Revisions
-
-
-
-
-
(1)
-
(1)
Improved recovery
-
-
-
-
-
-
-
-
Purchases
-
-
-
-
-
-
-
-
Extensions and discoveries
-
-
-
-
-
42
-
42
Production
-
-
-
-
-
(73)
-
(73)
Sales
-
-
-
-
-
-
-
-
End of 2019
-
-
-
-
-
848
-
848
Total company
End of 2016
1,294
1,570
2,864
1,482
528
1,309
241
6,424
End of 2017
1,430
1,353
2,783
254
517
1,251
233
5,038
End of 2018
1,795
1,312
3,107
245
465
1,222
224
5,263
End of 2019
1,779
1,447
3,226
296
360
1,146
234
5,262
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
150
 
Years Ended
Total Proved Reserves
December 31
Millions of Barrels of Oil Equivalent
Lower
Total
Asia Pacific/
Alaska
48
U.S.
Canada
Europe
Middle East
Africa
Total
Developed
Consolidated operations
End of 2016
1,203
1,165
2,368
391
365
309
241
3,674
End of 2017
1,319
682
2,001
158
372
281
233
3,045
End of 2018
1,617
681
2,298
160
382
244
221
3,305
End of 2019
1,582
666
2,248
197
275
236
218
3,174
Equity affiliates
End of 2016
-
-
-
322
-
820
-
1,142
End of 2017
-
-
-
-
-
802
-
802
End of 2018
-
-
-
-
-
796
-
796
End of 2019
-
-
-
-
-
761
-
761
Undeveloped
Consolidated operations
End of 2016
91
405
496
2
163
135
-
796
End of 2017
111
671
782
96
145
125
-
1,148
End of 2018
178
631
809
85
83
98
3
1,078
End of 2019
197
781
978
99
85
62
16
1,240
Equity affiliates
End of 2016
-
-
-
767
-
45
-
812
End of 2017
-
-
-
-
-
43
-
43
End of 2018
-
-
-
-
-
84
-
84
End of 2019
-
-
-
-
-
87
-
87
 
 
Natural gas reserves are converted to barrels of oil
 
equivalent (BOE) based on a 6:1 ratio:
 
six MCF of natural gas converts to
one BOE.
 
Proved Undeveloped Reserves
 
We
 
had 1,327 MMBOE of PUDs at year-end 2019,
 
compared with 1,162 MMBOE at year-end 2018.
 
The following table
shows changes in total proved undeveloped reserves
 
for 2019:
 
Proved Undeveloped Reserves
Millions of Barrels of
Oil Equivalent
End of 2018
1,162
Transfers to proved developed
(286)
Revisions
(5)
Improved recovery
7
Purchases
1
Extensions and discoveries
468
Sales
(20)
End of 2019
1,327
 
 
Transfers to proved developed reserves were driven by the ongoing development
 
of our assets. Approximately half of the
transfers were from the development of our Lower
 
48 unconventional plays. The remainder of
 
transfers were from development
across the Asia Pacific/Middle East, Alaska, Europe
 
and Canada regions.
 
 
 
151
 
Downward revisions were driven by changes in
 
development timing of 166 MMBOE primarily
 
in Lower 48 and Canada,
largely offset by upward revisions for infill drilling of 147
 
MMBOE primarily in Lower 48, Europe, Alaska
 
and Africa.
 
Extensions and discoveries were largely driven by an addition
 
of 358 MMBOE in Lower 48 for the continued development
 
of
unconventional plays. The remaining extensions and
 
discoveries were driven by the continued
 
development planned in Alaska,
Canada and Asia Pacific/Middle East.
 
 
Sales were due to the disposition of the U.K. assets.
 
At December 31, 2019, our PUDs represented 25
 
percent of total proved reserves, compared with
 
22 percent at December 31,
2018.
 
Costs incurred for the year ended December 31,
 
2019, relating to the development of PUDs were
 
$4.6 billion.
 
A portion
of our costs incurred each year relates to development
 
projects where the PUDs will be converted
 
to proved developed reserves
in future years.
 
 
At the end of 2019, more than 90 percent of total
 
PUDs were under development or scheduled
 
for development within five
years of initial disclosure. The remainder are to
 
be developed as parts of major projects ongoing
 
in our Canada, Asia
Pacific/Middle East and Europe regions.
 
All major development areas are currently producing
 
and are expected to have PUDs
convert to proved developed over time.
 
Of our total PUDs at year-end 2019, 81 percent
 
are in North America, and 95 percent of
these reserve volumes are planned for development within
 
five years of initial disclosure.
 
Results of Operations
 
 
The company’s results of operations from oil and gas activities for the years
 
2019, 2018 and 2017 are shown in the following
tables.
 
Non-oil and gas activities, such as pipeline and
 
marine operations, LNG operations, crude oil and
 
gas marketing
activities, and the profit element of transportation
 
operations in which we have an ownership
 
interest are excluded.
 
Additional
information about selected line items within the results
 
of operations tables is shown below:
 
●
 
Sales include sales to unaffiliated entities attributable primarily
 
to the company’s net working interests and royalty
interests.
 
Sales are net of fees to transport our produced hydrocarbons
 
beyond the production function to a final
delivery point using transportation operations which are
 
not consolidated.
 
●
 
Transportation costs reflect fees to transport our produced
 
hydrocarbons beyond the production function to
 
a final
delivery point using transportation operations which are
 
consolidated.
 
 
●
 
Other revenues include gains and losses from asset
 
sales, certain amounts resulting from the
 
purchase and sale of
hydrocarbons, and other miscellaneous income.
 
●
 
Production costs include costs incurred to operate and
 
maintain wells, related equipment
 
and facilities used in the
production of petroleum liquids and natural gas.
 
●
 
Taxes other than income taxes include production, property and other non-income taxes.
 
●
 
Depreciation of support equipment is reclassified
 
as applicable.
 
 
●
 
Other related expenses include inventory fluctuations,
 
foreign currency transaction gains and
 
losses and other
miscellaneous expenses.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
152
 
Results of Operations
Year Ended
Millions of Dollars
December 31, 2019
Lower
Total
 
 
Asia Pacific/
Other
Alaska
48
U.S.
Canada
Europe
Middle East
Africa
Areas
Total
Consolidated operations
Sales
$
4,883
6,356
11,239
709
3,207
3,032
919
-
19,106
Transfers
4
-
4
-
-
449
-
-
453
Transportation costs
(629)
-
(629)
-
-
(41)
-
-
(670)
Other revenues
61
78
139
86
1,785
12
101
326
2,449
Total revenues
4,319
6,434
10,753
795
4,992
3,452
1,020
326
21,338
Production costs excluding
 
taxes
1,235
1,578
2,813
380
741
619
70
(8)
4,615
Taxes other than income taxes
308
437
745
18
32
54
3
(2)
850
Exploration expenses
97
430
527
32
69
80
5
33
746
Depreciation, depletion
 
and
 
amortization
700
2,804
3,504
230
842
1,172
37
-
5,785
Impairments
-
402
402
2
1
-
-
-
405
Other related expenses
(12)
116
104
(38)
(42)
58
22
10
114
Accretion
62
49
111
7
142
43
-
-
303
1,929
618
2,547
164
3,207
1,426
883
293
8,520
Income tax provision (benefit)
444
147
591
(74)
591
458
833
7
2,406
Results of operations
$
1,485
471
1,956
238
2,616
968
50
286
6,114
Equity affiliates
Sales
$
-
-
-
-
-
599
-
-
599
Transfers
-
-
-
-
-
2,229
-
-
2,229
Transportation costs
-
-
-
-
-
-
-
-
-
Other revenues
-
-
-
-
-
31
-
-
31
Total revenues
-
-
-
-
-
2,859
-
-
2,859
Production costs excluding
 
taxes
-
-
-
-
-
335
-
-
335
Taxes other than income taxes
-
-
-
-
-
820
-
-
820
Exploration expenses
-
-
-
-
-
Depreciation, depletion
 
and
 
amortization
-
-
-
-
-
579
-
-
579
Impairments
-
-
-
-
-
-
-
-
-
Other related expenses
-
-
-
-
-
11
-
-
11
Accretion
-
-
-
-
-
16
-
-
16
-
-
-
-
-
1,098
-
-
1,098
Income tax provision (benefit)
-
-
-
-
-
170
-
-
170
Results of operations
$
-
-
-
-
-
928
-
-
928
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
153
 
Year Ended
Millions of Dollars
December 31, 2018
Lower
Total
 
 
Asia Pacific/
Other
Alaska
48
U.S.
Canada
Europe
Middle East
Africa
Areas
Total
Consolidated operations
Sales
$
4,816
6,573
11,389
582
4,449
3,177
950
-
20,547
Transfers
5
-
5
-
-
545
-
-
550
Transportation costs
(722)
-
(722)
-
-
(45)
-
-
(767)
Other revenues
335
213
548
164
737
6
110
432
1,997
Total revenues
4,434
6,786
11,220
746
5,186
3,683
1,060
432
22,327
Production costs excluding
 
taxes
964
1,533
2,497
417
856
646
62
2
4,480
Taxes other than income taxes
357
432
789
21
33
95
3
-
941
Exploration expenses
59
176
235
21
57
43
(4)
20
372
Depreciation, depletion
 
and
 
amortization
616
2,279
2,895
313
1,070
1,186
33
-
5,497
Impairments
1
64
65
9
(78)
14
-
-
10
Other related expenses
16
63
79
56
(62)
(19)
1
(1)
54
Accretion
56
51
107
7
178
39
-
-
331
2,365
2,188
4,553
(98)
3,132
1,679
965
411
10,642
Income tax provision (benefit)
419
466
885
(114)
1,354
683
926
(8)
3,726
Results of operations
$
1,946
1,722
3,668
16
1,778
996
39
419
6,916
Equity affiliates
Sales
$
-
-
-
-
-
758
-
-
758
Transfers
-
-
-
-
-
2,018
-
-
2,018
Transportation costs
-
-
-
-
-
-
-
-
-
Other revenues
-
-
-
-
-
(6)
-
-
(6)
Total revenues
-
-
-
-
-
2,770
-
-
2,770
Production costs excluding
 
taxes
-
-
-
-
-
321
-
-
321
Taxes other than income taxes
-
-
-
-
-
804
-
-
804
Exploration expenses
-
-
-
-
-
Depreciation, depletion
 
and
 
amortization
-
-
-
-
-
640
-
-
640
Impairments
-
-
-
-
-
-
-
-
-
Other related expenses
-
-
-
-
-
(4)
-
-
(4)
Accretion
-
-
-
-
-
15
-
-
15
-
-
-
-
-
994
-
-
994
Income tax provision (benefit)
-
-
-
-
-
103
-
-
103
Results of operations
$
-
-
-
-
-
891
-
-
891
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
154
 
Year Ended
Millions of Dollars
December 31, 2017
Lower
Total
 
 
Asia Pacific/
 
Other
Alaska
48
U.S.
Canada
Europe
Middle East
Africa
Areas
Total
Consolidated operations
Sales
$
3,542
4,557
8,099
705
3,527
2,752
487
-
15,570
Transfers
4
-
4
-
-
411
-
-
415
Transportation costs
(706)
-
(706)
-
-
(80)
-
-
(786)
Other revenues
14
28
42
2,158
68
11
48
322
2,649
Total revenues
2,854
4,585
7,439
2,863
3,595
3,094
535
322
17,848
Production costs excluding
 
taxes
947
1,607
2,554
604
770
566
44
(1)
4,537
Taxes other than income taxes
275
318
593
33
32
39
2
-
699
Exploration expenses
83
584
667
22
45
97
61
45
937
Depreciation, depletion
 
and
 
amortization
730
2,685
3,415
438
1,234
1,283
16
-
6,386
Impairments
179
3,969
4,148
22
46
-
-
-
4,216
Other related expenses
(7)
62
55
7
57
60
6
-
185
Accretion
52
63
115
16
172
37
-
-
340
595
(4,703)
(4,108)
1,721
1,239
1,012
406
278
548
Income tax provision (benefit)
(669)
(2,401)
(3,070)
(651)
702
363
428
11
(2,217)
Results of operations
$
1,264
(2,302)
(1,038)
2,372
537
649
(22)
267
2,765
Equity affiliates
Sales
$
-
-
-
528
-
563
-
-
1,091
Transfers
-
-
-
-
-
1,398
-
-
1,398
Transportation costs
-
-
-
-
-
-
-
-
-
Other revenues
-
-
-
5
-
-
-
-
5
Total revenues
-
-
-
533
-
1,961
-
-
2,494
Production costs excluding
 
taxes
-
-
-
174
-
363
-
-
537
Taxes other than income taxes
-
-
-
7
-
604
-
-
611
Exploration expenses
-
-
-
1
1,699
-
1,700
Depreciation, depletion
 
and
 
amortization
-
-
-
150
-
617
-
-
767
Impairments
-
-
-
-
-
1,717
-
-
1,717
Other related expenses
-
-
-
4
-
22
-
19
45
Accretion
-
-
-
2
-
11
-
-
13
-
-
-
195
-
(3,072)
-
(19)
(2,896)
Income tax provision (benefit)
-
-
-
26
-
(998)
-
13
(959)
Results of operations
$
-
-
-
169
-
(2,074)
-
(32)
(1,937)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
155
 
Statistics
 
Net Production
2019
2018
2017
Thousands of Barrels Daily
Crude Oil
 
Consolidated operations
Alaska
 
202
171
167
Lower 48
266
229
180
United States
468
400
347
Canada
1
1
3
Europe
100
113
122
Asia Pacific
85
89
93
Africa
38
36
20
Total consolidated operations
692
639
585
Equity affiliates—
Asia Pacific/Middle East
13
14
14
Total company
705
653
599
Greater Prudhoe Area (Alaska)*
66
71
74
Natural Gas Liquids
Consolidated operations
Alaska
 
15
14
14
Lower 48
81
69
69
United States
96
83
83
Canada
-
1
9
Europe
7
8
8
Asia Pacific
4
3
4
Total consolidated operations
107
95
104
Equity affiliates—
Asia Pacific/Middle East
8
7
7
Total company
115
102
111
Greater Prudhoe Area (Alaska)*
15
14
14
Bitumen
Consolidated operations—
Canada
60
66
59
Equity affiliates—
Canada
 
63
Total company
60
66
122
Natural Gas
Millions of Cubic Feet Daily
Consolidated operations
Alaska
7
6
7
Lower 48
622
596
898
United States
629
602
905
Canada
9
12
187
Europe
447
475
476
Asia Pacific
637
626
687
Africa
31
28
8
Total consolidated operations
1,753
1,743
2,263
Equity affiliates—
Asia Pacific/Middle East
1,052
1,031
1,007
Total company
2,805
2,774
3,270
Greater Prudhoe Area (Alaska)*
4
5
5
*At year-end 2019, the Greater
 
Prudhoe Area in Alaska
 
contained more than 15%
 
of total proved reserves.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
156
 
Average Sales Prices
2019
2018
2017
Crude Oil Per Barrel
 
Consolidated operations
Alaska
$
55.85
60.23
42.69
Lower 48
55.30
62.99
47.36
United States
55.54
61.75
45.01
Canada
40.87
48.73
43.69
Europe
65.12
70.98
54.04
Asia Pacific
65.02
70.93
54.38
Africa
64.47
69.83
55.11
Total international
64.85
70.67
54.16
Total consolidated operations
58.51
65.01
48.70
Equity affiliates
—Asia Pacific/Middle East
61.32
72.49
54.76
Total operations
58.57
65.17
48.84
Natural Gas Liquids Per Barrel
 
Consolidated operations
Lower 48
$
16.83
27.30
22.20
United States
16.85
27.30
22.20
Canada
19.87
43.70
21.51
Europe
29.37
36.87
34.07
Asia Pacific
37.85
47.20
41.37
Total international
32.29
40.00
30.34
Total consolidated operations
18.73
29.03
24.21
Equity affiliates
—Asia Pacific/Middle East
36.70
45.69
38.74
Total operations
20.09
30.48
25.22
Bitumen Per Barrel
Consolidated operations—
Canada
$
31.72
22.29
21.43
Equity affiliates—
Canada
23.83
Natural Gas Per Thousand Cubic Feet
Consolidated operations
Alaska
$
3.19
2.48
2.72
Lower 48
2.12
2.82
2.73
United States
2.12
2.82
2.73
Canada
0.49
1.00
1.93
Europe
4.92
7.79
5.72
Asia Pacific
5.73
5.95
4.66
Africa
4.87
4.84
3.53
Total international
5.35
6.64
4.64
Total consolidated operations
4.19
5.33
3.87
Equity affiliates
—Asia Pacific/Middle East
6.29
6.06
4.27
Total operations
4.99
5.60
4.00
Average sales
 
prices for Alaska crude oil and
 
Asia Pacific natural gas above
 
reflect a reduction
 
for transportation costs in which
 
we
have an ownership interest
 
that are incurred
 
subsequent to the terminal point of the
 
production
 
function.
 
Accordingly,
 
the average sales prices
differ from those discussed
 
in Item 7 of Management's Discussion
 
and Analysis of Financial Condition
 
and Results of Operation
 
s.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
157
 
2019
2018
2017
Average Production Costs Per Barrel of Oil Equivalent*
Consolidated operations
Alaska
$
15.52
14.20
14.26
Lower 48
9.59
10.58
11.03
United States
11.52
11.73
12.04
Canada
16.53
16.32
16.22
Europe
11.22
11.73
10.09
Asia Pacific
8.74
9.03
7.31
Africa
4.46
4.14
5.74
Total international
10.26
10.72
9.99
Total consolidated operations
10.99
11.26
11.05
Equity affiliates
Canada
7.57
Asia Pacific/Middle East
4.68
4.56
5.26
Total equity affiliates
4.68
4.56
5.84
Average Production Costs Per Barrel—Bitumen
Consolidated operations—
Canada
$
13.74
13.59
14.63
Equity affiliates—
Canada
18.74
Taxes Other Than Income Taxes Per Barrel of Oil Equivalent
Consolidated operations
Alaska
$
3.87
5.26
4.14
Lower 48
2.65
2.98
2.18
United States
3.05
3.71
2.80
Canada
0.78
0.82
0.89
Europe
0.48
0.45
0.42
Asia Pacific
0.76
1.33
0.50
Africa
0.19
0.20
0.26
Total international
0.60
0.82
0.53
Total consolidated operations
2.03
2.37
1.70
Equity affiliates
Canada
0.30
Asia Pacific/Middle East
11.46
11.41
8.76
Total equity affiliates
11.46
11.41
6.64
Depreciation, Depletion and Amortization
 
Per Barrel of Oil Equivalent
Consolidated operations
Alaska
$
8.80
9.07
10.99
Lower 48
17.03
15.73
18.44
United States
14.35
13.60
16.10
Canada
10.00
12.25
11.76
Europe
12.75
14.66
16.18
Asia Pacific
16.55
16.58
16.58
Africa
2.36
2.21
2.09
Total international
12.99
14.06
14.96
Total consolidated operations
13.78
13.82
15.55
Equity affiliates
Canada
6.52
Asia Pacific/Middle East
8.09
9.09
8.94
Total equity affiliates
8.09
9.09
8.34
*Includes bitumen.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
158
 
Development and Exploration Activities
The following two tables summarize our net interest in
 
productive and dry exploratory and development
 
wells
in the years ended December 31, 2019, 2018 and 2017.
 
A “development well” is a well drilled within
 
the
proved area of a reservoir to the depth of a stratigraphic
 
horizon known to be productive.
 
An “exploratory
well” is a well drilled to find and produce crude oil
 
or natural gas in an unknown field or a new reservoir
within a proven field.
 
Exploratory wells also include wells
 
drilled in areas near or offsetting current
production, or in areas where well density or production
 
history have not achieved statistical certainty
 
of
results.
 
Excluded from the exploratory well count
 
are stratigraphic-type exploratory wells, primarily relating
to oil sands delineation wells located in Canada and
 
CBM test wells located in Asia Pacific/Middle
 
East.
 
 
 
Net Wells Completed
Productive
Dry
2019
2018
2017
2019
2018
2017
Exploratory
Consolidated operations
Alaska
7
6
-
-
-
-
Lower 48
35
45
13
6
1
3
United States
42
51
13
6
1
3
Canada
-
2
13
-
-
-
Europe
1
*
*
1
*
*
Asia Pacific
1
2
1
1
-
1
Africa
-
-
-
-
*
-
Other areas
-
-
-
-
-
1
Total consolidated operations
44
55
27
8
1
5
Equity affiliates
Asia Pacific/Middle East
8
6
14
-
2
-
Total equity affiliates
8
6
14
-
2
-
Development
Consolidated operations
 
 
Alaska
12
11
9
-
-
-
Lower 48
255
254
161
-
-
-
United States
267
265
170
-
-
-
Canada
2
1
13
-
-
-
Europe
6
9
7
-
-
-
Asia Pacific
21
12
8
-
-
-
Africa
2
1
-
-
-
-
Other areas
-
-
-
-
-
-
Total consolidated operations
298
288
198
-
-
-
Equity affiliates
Canada
-
-
19
-
-
-
Asia Pacific/Middle East
106
75
84
-
-
-
Other areas
-
-
-
-
-
-
Total equity affiliates
106
75
103
-
-
-
*Our total proportionate
 
interest was less than one.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
159
 
The table below represents the status of our wells drilling
 
at December 31, 2019, and includes wells in the
process of drilling or in active completion.
 
It also represents gross and net productive
 
wells, including
producing wells and wells capable of production
 
at December 31, 2019.
Wells at December 31, 2019
Productive
In Progress
Oil
Gas
Gross
Net
Gross
Net
Gross
Net
Consolidated operations
Alaska
4
4
1,656
997
-
-
Lower 48
349
170
10,070
4,547
4,329
1,704
United States
353
174
11,726
5,544
4,329
1,704
Canada
32
32
186
93
31
27
Europe
19
1
469
79
55
2
Asia Pacific
12
6
302
143
56
28
Africa
13
2
840
137
7
1
Other areas
14
7
-
-
-
-
Total consolidated operations
443
222
13,523
5,996
4,478
1,762
Equity affiliates
Asia Pacific/Middle East
325
79
-
-
4,307
1,051
Total equity affiliates
325
79
-
-
4,307
1,051
 
 
Acreage at December 31, 2019
Thousands of Acres
Developed
Undeveloped
Gross
Net
Gross
Net
Consolidated operations
Alaska
651
467
1,331
1,320
Lower 48
2,569
2,012
10,337
8,396
United States
3,220
2,479
11,668
9,716
Canada
206
126
3,270
1,798
Europe
430
50
2,102
610
Asia Pacific
1,538
721
9,910
5,735
Africa
358
58
12,545
2,049
Other areas
-
-
1,400
742
Total consolidated operations
5,752
3,434
40,895
20,650
Equity affiliates
Asia Pacific/Middle East
933
229
3,723
840
Total equity affiliates
933
229
3,723
840
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
160
 
Costs Incurred
Year
 
Ended
Millions of Dollars
December 31
Lower
Total
Asia Pacific/
Other
Alaska
48
U.S.
Canada
Europe
Middle East
Africa
Areas
Total
2019
Consolidated operations
Unproved property acquisition
$
101
45
146
14
-
-
-
197
357
Proved property acquisition
1
116
117
-
-
115
-
-
232
102
161
263
14
-
115
-
197
589
Exploration
281
390
671
200
119
66
8
39
1,103
Development
1,125
3,028
4,153
215
625
486
22
-
5,501
$
1,508
3,579
5,087
429
744
667
30
236
7,193
Equity affiliates
Unproved property acquisition
$
-
-
-
-
-
62
-
-
62
Proved property acquisition
-
-
-
-
-
-
-
62
-
-
62
Exploration
-
-
-
-
-
23
-
-
23
Development
-
-
-
-
-
171
-
-
171
$
-
-
-
-
-
256
-
-
256
2018
Consolidated operations
Unproved property acquisition
$
119
126
245
126
-
-
-
-
371
Proved property acquisition
2,227
16
2,243
6
-
-
-
-
2,249
2,346
142
2,488
132
-
-
-
-
2,620
Exploration
203
500
703
90
65
82
(6)
41
975
Development
718
2,715
3,433
301
703
773
16
-
5,226
$
3,267
3,357
6,624
523
768
855
10
41
8,821
Equity affiliates
Unproved property acquisition
$
-
-
-
-
-
-
-
-
-
Proved property acquisition
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
Exploration
-
-
-
-
-
22
-
-
22
Development
-
-
-
-
-
206
-
-
206
$
-
-
-
-
-
228
-
-
228
2017
Consolidated operations
Unproved property acquisition
$
18
267
285
76
-
15
-
-
376
Proved property acquisition
-
35
35
-
-
-
-
-
35
18
302
320
76
-
15
-
-
411
Exploration
74
399
473
56
52
139
61
42
823
Development
736
1,559
2,295
102
784
388
10
-
3,579
$
828
2,260
3,088
234
836
542
71
42
4,813
Equity affiliates
Unproved property acquisition
$
-
-
-
-
-
-
-
-
-
Proved property acquisition
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
Exploration
-
-
-
6
-
38
-
-
44
Development
-
-
-
150
-
403
-
-
553
$
-
-
-
156
-
441
-
-
597
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
161
 
Capitalized Costs
At December 31
Millions of Dollars
Lower
Total
Asia Pacific/
Other
Alaska
48
U.S.
Canada
Europe
Middle East
Africa
Areas
Total
2019
Consolidated operations
Proved property
$
20,957
37,491
58,448
6,673
14,113
14,566
924
-
94,724
Unproved property
1,429
1,055
2,484
1,149
87
501
123
290
4,634
22,386
38,546
60,932
7,822
14,200
15,067
1,047
290
99,358
Accumulated depreciation,
depletion and amortization
9,419
26,294
35,713
2,050
9,017
10,253
379
9
57,421
$
12,967
12,252
25,219
5,772
5,183
4,814
668
281
41,937
Equity affiliates
Proved property
$
-
-
-
-
-
9,996
-
-
9,996
Unproved property
-
-
-
-
-
2,223
-
-
2,223
-
-
-
-
-
12,219
-
-
12,219
Accumulated depreciation,
depletion and amortization
-
-
-
-
-
6,390
-
-
6,390
$
-
-
-
-
-
5,829
-
-
5,829
2018
Consolidated operations
Proved property
$
20,154
35,269
55,423
5,946
23,520
14,866
902
-
100,657
Unproved property
1,184
1,125
2,309
1,083
188
874
119
89
4,662
21,338
36,394
57,732
7,029
23,708
15,740
1,021
89
105,319
Accumulated depreciation,
depletion and amortization
9,055
23,999
33,054
1,692
16,591
9,974
342
9
61,662
$
12,283
12,395
24,678
5,337
7,117
5,766
679
80
43,657
Equity affiliates
Proved property
$
-
-
-
-
-
9,990
-
-
9,990
Unproved property
-
-
-
-
-
2,162
-
-
2,162
-
-
-
-
-
12,152
-
-
12,152
Accumulated depreciation,
depletion and amortization
-
-
-
-
-
5,960
-
-
5,960
$
-
-
-
-
-
6,192
-
-
6,192
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
162
 
Standardized Measure of Discounted Future Net Cash
 
Flows Relating to Proved Oil and Gas Reserve Quantities
 
In accordance with SEC and FASB requirements, amounts were computed using 12-month
 
average prices (adjusted only for
existing contractual terms)
 
and end-of-year costs, appropriate statutory
 
tax rates and a prescribed 10 percent discount
 
factor.
 
Twelve-month average prices are calculated as the unweighted arithmetic average
 
of the first-day-of-the-month price for each
month within the 12-month period prior to the end of
 
the reporting period.
 
For all years, continuation of year-end economic
conditions was assumed.
 
The calculations were based on estimates of proved
 
reserves, which are revised over time as
 
new data
becomes available.
 
Probable or possible reserves, which may
 
become proved in the future, were not considered.
 
The
calculations also require assumptions as to the timing
 
of future production of proved reserves and
 
the timing and amount of
future development costs, including dismantlement,
 
and future production costs, including taxes other
 
than income taxes.
 
While due care was taken in its preparation, we
 
do not represent that this data is the fair value of
 
our oil and gas properties, or a
fair estimate of the present value of cash flows to
 
be obtained from their development and production.
 
Discounted Future Net Cash Flows
Millions of Dollars
Lower
Total
Asia Pacific/
Alaska
48
U.S.
Canada
Europe
Middle East
Africa
Total
2019
Consolidated operations
Future cash inflows
$
70,341
53,400
123,741
8,244
16,919
13,084
15,582
177,570
Less:
Future production costs
40,464
22,194
62,658
4,525
5,843
5,162
1,314
79,502
Future development costs
9,721
14,083
23,804
577
4,143
2,179
484
31,187
Future income tax provisions
3,904
2,793
6,697
-
4,201
1,931
12,747
25,576
Future net cash flows
16,252
14,330
30,582
3,142
2,732
3,812
1,037
41,305
10 percent annual discount
6,571
4,311
10,882
1,198
558
835
460
13,933
Discounted future net cash flows
$
9,681
10,019
19,700
1,944
2,174
2,977
577
27,372
Equity affiliates
Future cash inflows
$
-
-
-
-
-
31,671
-
31,671
Less:
Future production costs
-
-
-
-
-
16,157
-
16,157
Future development costs
-
-
-
-
-
1,218
-
1,218
Future income tax provisions
-
-
-
-
-
3,086
-
3,086
Future net cash flows
-
-
-
-
-
11,210
-
11,210
10 percent annual discount
-
-
-
-
-
4,040
-
4,040
Discounted future net cash flows
$
-
-
-
-
-
7,170
-
7,170
Total company
Discounted future net cash flows
$
9,681
10,019
19,700
1,944
2,174
10,147
577
34,542
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
163
 
Millions of Dollars
Lower
Total
Asia Pacific/
Alaska
48
U.S.
Canada
Europe
Middle East
Africa
Total
2018
Consolidated operations
Future cash inflows
$
82,072
56,922
138,994
6,039
26,989
16,368
16,434
204,824
Less:
Future production costs
42,755
21,363
64,118
4,099
8,567
5,705
1,336
83,825
Future development costs
10,053
12,136
22,189
606
7,608
1,995
507
32,905
Future income tax provisions
5,538
4,418
9,956
-
7,102
2,873
13,492
33,423
Future net cash flows
23,726
19,005
42,731
1,334
3,712
5,795
1,099
54,671
10 percent annual discount
10,349
6,461
16,810
426
371
1,132
498
19,237
Discounted future net cash flows
$
13,377
12,544
25,921
908
3,341
4,663
601
35,434
Equity affiliates
Future cash inflows
$
-
-
-
-
-
33,606
-
33,606
Less:
Future production costs
-
-
-
-
-
16,449
-
16,449
Future development costs
-
-
-
-
-
1,228
-
1,228
Future income tax provisions
-
-
-
-
-
3,147
-
3,147
Future net cash flows
-
-
-
-
-
12,782
-
12,782
10 percent annual discount
-
-
-
-
-
4,853
-
4,853
Discounted future net cash flows
$
-
-
-
-
-
7,929
-
7,929
Total company
Discounted future net cash flows
$
13,377
12,544
25,921
908
3,341
12,592
601
43,363
 
 
Millions of Dollars
Lower
Total
Asia Pacific/
Alaska
48
U.S.
Canada
Europe
Middle East
Africa
Total
2017
Consolidated operations
Future cash inflows
$
44,969
44,556
89,525
5,479
23,137
15,207
13,181
146,529
Less:
Future production costs
29,524
18,947
48,471
4,417
8,128
5,398
1,401
67,815
Future development costs
7,255
10,881
18,136
696
8,758
2,511
537
30,638
Future income tax provisions
53
2,375
2,428
-
3,333
2,459
10,356
18,576
Future net cash flows
8,137
12,353
20,490
366
2,918
4,839
887
29,500
10 percent annual discount
2,712
4,358
7,070
78
289
1,032
422
8,891
Discounted future net cash flows
$
5,425
7,995
13,420
288
2,629
3,807
465
20,609
Equity affiliates
Future cash inflows
$
-
-
-
-
-
23,222
-
23,222
Less:
Future production costs
-
-
-
-
-
12,984
-
12,984
Future development costs
-
-
-
-
-
1,444
-
1,444
Future income tax provisions
-
-
-
-
-
2,083
-
2,083
Future net cash flows
-
-
-
-
-
6,711
-
6,711
10 percent annual discount
-
-
-
-
-
2,316
-
2,316
Discounted future net cash flows
$
-
-
-
-
-
4,395
-
4,395
Total company
Discounted future net cash flows
$
5,425
7,995
13,420
288
2,629
8,202
465
25,004
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
164
 
Sources of Change in Discounted Future Net Cash Flows
Millions of Dollars
Consolidated Operations
Equity Affiliates
Total Company
2019
2018
2017
2019
2018
2017
2019
2018
2017
Discounted future net
 
cash flows
 
at the beginning of the year
$
35,434
20,609
8,151
7,929
4,395
3,937
43,363
25,004
12,088
Changes during the year
Revenues less production
 
costs for the year
(13,424)
(14,909)
(9,844)
(1,673)
(1,651)
(1,341)
(15,097)
(16,560)
(11,185)
Net change in prices
 
and
production costs
(13,538)
25,391
19,310
(422)
4,559
2,750
(13,960)
29,950
22,060
Extensions, discoveries
 
and
improved recovery, less
estimated future costs
2,985
4,574
1,445
260
382
(4)
3,245
4,956
1,441
Development costs for the
 
year
5,333
5,197
3,653
239
271
426
5,572
5,468
4,079
Changes in estimated future
development costs
559
(1,141)
1,225
(21)
14
(64)
538
(1,127)
1,161
Purchases of reserves in place,
 
less estimated future costs
10
3,033
-
-
-
-
10
3,033
-
Sales of reserves in place,
 
less estimated future costs
(1,997)
(1,531)
(855)
-
-
(786)
(1,997)
(1,531)
(1,641)
Revisions of previous
 
quantity
estimates
2,099
(365)
2,300
69
62
(648)
2,168
(303)
1,652
Accretion of discount
5,144
3,055
1,313
869
485
413
6,013
3,540
1,726
Net change in income
 
taxes
4,767
(8,479)
(6,089)
(80)
(588)
(288)
4,687
(9,067)
(6,377)
Total changes
(8,062)
14,825
12,458
(759)
3,534
458
(8,821)
18,359
12,916
Discounted future net
 
cash flows
at year end
$
27,372
35,434
20,609
7,170
7,929
4,395
34,542
43,363
25,004
 
●
 
The net change in prices and production costs is
 
the beginning-of-year reserve-production forecast
 
multiplied by the net
annual change in the per-unit sales price and production
 
cost, discounted at 10 percent.
 
●
 
Purchases and sales of reserves in place, along with
 
extensions, discoveries and improved recovery, are calculated using
production forecasts of the applicable reserve
 
quantities for the year multiplied by the 12-month average
 
sales prices, less
future estimated costs, discounted at 10 percent.
 
 
●
 
Revisions of previous quantity estimates are calculated
 
using production forecast changes for
 
the year, including changes in
the timing of production, multiplied by the 12-month
 
average sales prices, less future estimated
 
costs, discounted at
10 percent.
 
●
 
The accretion of discount is 10 percent of the prior year’s discounted
 
future cash inflows, less future production and
development costs.
 
●
 
The net change in income taxes is the annual change
 
in the discounted future income tax provisions.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
165
 
Selected Quarterly Financial Data
(Unaudited)
Millions of Dollars
Per Share of Common Stock
Sales and
Net Income
Net Income (Loss)
 
Other
Income (Loss)
Net
(Loss)
Attributable
Operating
Before
Income
Attributable to
to ConocoPhillips
 
Revenues
Income Taxes
(Loss)
ConocoPhillips
Basic
Diluted
2019
First
$
9,150
2,687
1,846
1,833
1.61
1.60
Second
7,953
2,058
1,597
1,580
1.40
1.40
Third
7,756
3,493
3,071
3,056
2.76
2.74
Fourth
7,708
1,286
743
720
0.66
0.66
2018
First
$
 
8,798
1,776
900
888
0.75
0.75
Second
8,504
2,619
1,654
1,640
1.40
1.39
Third
9,449
2,906
1,873
1,861
1.60
1.59
Fourth
9,666
2,672
1,878
1,868
1.62
1.61
For additional information
 
on the commodity price environment,
 
see the Business Environment
 
and Executive Overview section
 
of Management's Discussion
 
and
Analysis of Financial Condition
 
and Results of Operations.
 
 
166
 
Supplementary Information—Condensed Consolidating
 
Financial Information
 
We
 
have various cross guarantees among ConocoPhillips,
 
ConocoPhillips Company and Burlington Resources
LLC, with respect to publicly held debt securities.
 
ConocoPhillips Company is 100 percent owned
 
by
ConocoPhillips.
 
Burlington Resources LLC is 100 percent owned by
 
ConocoPhillips Company.
 
ConocoPhillips and/or ConocoPhillips Company
 
have fully and unconditionally guaranteed
 
the payment
obligations of Burlington Resources LLC, with respect
 
to its publicly held debt securities.
 
Similarly,
ConocoPhillips has fully and unconditionally guaranteed
 
the payment obligations of ConocoPhillips
 
Company
with respect to its publicly held debt securities.
 
In addition, ConocoPhillips
 
Company has fully and
unconditionally guaranteed the payment obligations of
 
ConocoPhillips with respect to its publicly
 
held debt
securities.
 
All guarantees are joint and several.
 
The following condensed consolidating financial
 
information
presents the results of operations, financial position
 
and cash flows for:
 
●
 
ConocoPhillips, ConocoPhillips Company and Burlington
 
Resources LLC (in each case, reflecting
investments in subsidiaries utilizing the equity method
 
of accounting).
●
 
All other nonguarantor subsidiaries of ConocoPhillips.
●
 
The consolidating adjustments necessary to present ConocoPhillips’
 
results on a consolidated basis.
 
In 2017, ConocoPhillips Company received a $
9.8
 
billion return of capital and a $
1.4
 
billion loan repayment
from nonguarantor subsidiaries to settle certain accumulated
 
intercompany balances.
 
These transactions had
no impact on our consolidated financial statements.
 
In 2017, ConocoPhillips received a $
7.8
 
billion return of capital and a $
0.2
 
billion return of earnings from
ConocoPhillips Company to settle certain accumulated
 
intercompany balances.
 
These transactions had no
impact on our consolidated financial statements.
 
In 2018, ConocoPhillips Company received a $
4.8
 
billion return of earnings and a $
2.4
 
billion loan repayment
from nonguarantor subsidiaries to settle certain accumulated
 
intercompany balances.
 
These transactions had
no impact on our consolidated financial statements.
 
 
In 2018, ConocoPhillips received a $
3.5
 
billion return of capital and a $
1.0
 
billion return of earnings from
ConocoPhillips Company to settle certain accumulated
 
intercompany balances.
 
These transactions had no
impact on our consolidated financial statements.
 
In 2019, ConocoPhillips received a $
2.4
 
billion return of capital and a $
1.7
 
billion return of earnings from
ConocoPhillips Company to settle certain accumulated
 
intercompany balances.
 
This transaction had no impact
on our consolidated financial statements.
 
 
In 2019, ConocoPhillips Company received a $
4.5
 
billion return of earnings and a $
4.2
 
billion return of capital
from nonguarantor subsidiaries to settle certain accumulated
 
intercompany balances.
 
These transactions had
no impact on our consolidated financial statements.
 
In 2019, Burlington Resources LLC received a $
3.2
 
billion return of earnings from nonguarantor subsidiaries
to settle certain accumulated intercompany balances.
 
These transactions had no impact on our consolidated
financial statements.
 
This condensed consolidating financial information
 
should be read in conjunction with the accompanying
consolidated financial statements and notes.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
167
 
Millions of Dollars
Year Ended
 
December 31, 2019
Income Statement
ConocoPhillips
ConocoPhillips
Company
Burlington
Resources LLC
All Other
Subsidiaries
Consolidating
Adjustments
Total
Consolidated
Revenues and Other Income
Sales and other operating revenues
$
-
14,510
-
18,057
-
32,567
Equity in earnings of affiliates
7,419
5,281
1,610
775
(14,306)
779
Gain (loss) on dispositions
-
2,786
-
(820)
-
1,966
Other income
1
875
5
477
-
1,358
Intercompany revenues
-
113
40
5,542
(5,695)
-
Total Revenues and
 
Other Income
7,420
23,565
1,655
24,031
(20,001)
36,670
Costs and Expenses
Purchased commodities
-
12,838
-
4,038
(5,034)
11,842
Production and operating expenses
1
1,380
1
4,345
(405)
5,322
Selling, general and administrative expenses
9
421
-
131
(5)
556
Exploration expenses
-
422
-
321
-
743
Depreciation, depletion and amortization
-
596
-
5,494
-
6,090
Impairments
-
157
-
248
-
405
Taxes other than income taxes
-
139
-
814
-
953
Accretion on discounted liabilities
-
16
-
310
-
326
Interest and debt expense
283
544
133
69
(251)
778
Foreign currency transaction losses
-
21
-
45
-
66
Other expenses
-
60
-
5
-
65
Total Costs and Expenses
293
16,594
134
15,820
(5,695)
27,146
Income before income taxes
7,127
6,971
1,521
8,211
(14,306)
9,524
Income tax provision (benefit)
(62)
(448)
(46)
2,823
-
2,267
Net income
7,189
7,419
1,567
5,388
(14,306)
7,257
Less: net income attributable to noncontrolling
 
interests
-
-
-
(68)
-
(68)
Net Income Attributable to ConocoPhillips
$
7,189
7,419
1,567
5,320
(14,306)
7,189
Comprehensive Income Attributable
 
to ConocoPhillips
$
7,935
8,165
1,873
6,058
(16,096)
7,935
Income Statement
Year Ended
 
December 31, 2018
Revenues and Other Income
Sales and other operating revenues
$
-
16,113
-
20,304
-
36,417
Equity in earnings of affiliates
6,503
8,142
1,953
1,072
(16,596)
1,074
Gain on dispositions
-
239
-
824
-
1,063
Other income (loss)
-
(384)
-
557
-
173
Intercompany revenues
35
162
43
5,627
(5,867)
-
Total Revenues and
 
Other Income
6,538
24,272
1,996
28,384
(22,463)
38,727
Costs and Expenses
Purchased commodities
-
14,591
-
5,131
(5,428)
14,294
Production and operating expenses
-
1,023
4
4,245
(59)
5,213
Selling, general and administrative expenses
8
289
-
109
(5)
401
Exploration expenses
-
170
-
199
-
369
Depreciation, depletion and amortization
-
584
-
5,372
-
5,956
Impairments
-
(10)
-
37
-
27
Taxes other than income taxes
-
143
-
905
-
1,048
Accretion on discounted liabilities
-
17
-
336
-
353
Interest and debt expense
295
613
46
156
(375)
735
Foreign currency transaction (gains) losses
46
(12)
116
(167)
-
(17)
Other expenses
-
349
6
20
-
375
Total Costs and Expenses
349
17,757
172
16,343
(5,867)
28,754
Income before income taxes
6,189
6,515
1,824
12,041
(16,596)
9,973
Income tax provision (benefit)
(68)
12
(41)
3,765
-
3,668
Net income
6,257
6,503
1,865
8,276
(16,596)
6,305
Less: net income attributable to noncontrolling
 
interests
-
-
-
(48)
-
(48)
Net Income Attributable to ConocoPhillips
$
6,257
6,503
1,865
8,228
(16,596)
6,257
Comprehensive Income Attributable
 
to ConocoPhillips
$
5,654
5,900
1,364
7,961
(15,225)
5,654
See Notes to Consolidated Financial Statements.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
168
 
Millions of Dollars
Year Ended
 
December 31, 2017
Income Statement
ConocoPhillips
ConocoPhillips
Company
Burlington
Resources LLC
All Other
Subsidiaries
Consolidating
Adjustments
Total
Consolidated
Revenues and Other Income
Sales and other operating revenues
$
-
12,433
-
16,673
-
29,106
Equity in earnings (losses) of affiliates
(454)
2,047
886
770
(2,477)
772
Gain on dispositions
-
916
-
1,261
-
2,177
Other income
2
35
-
492
-
529
Intercompany revenues
48
291
13
3,369
(3,721)
-
Total Revenues and
 
Other Income
(404)
15,722
899
22,565
(6,198)
32,584
Costs and Expenses
Purchased commodities
-
11,145
-
4,580
(3,250)
12,475
Production and operating expenses
-
813
-
4,366
(17)
5,162
Selling, general and administrative expenses
9
342
-
82
(6)
427
Exploration expenses
-
542
-
392
-
934
Depreciation, depletion and amortization
-
855
-
5,990
-
6,845
Impairments
-
1,159
-
5,442
-
6,601
Taxes other than income taxes
-
140
1
668
-
809
Accretion on discounted liabilities
-
32
-
330
-
362
Interest and debt expense
420
664
52
410
(448)
1,098
Foreign currency transaction (gains) losses
(43)
11
(137)
204
-
35
Other expenses
267
190
-
(6)
-
451
Total Costs and Expenses
653
15,893
(84)
22,458
(3,721)
35,199
Income (Loss) before income taxes
(1,057)
(171)
983
107
(2,477)
(2,615)
Income tax provision (benefit)
(202)
283
(337)
(1,566)
-
(1,822)
Net income (loss)
(855)
(454)
1,320
1,673
(2,477)
(793)
Less: net income attributable to noncontrolling
 
interests
-
-
-
(62)
-
(62)
Net Income (Loss) Attributable to ConocoPhillips
$
(855)
(454)
1,320
1,611
(2,477)
(855)
Comprehensive Income (Loss) Attributable
 
to ConocoPhillips
$
(180)
221
1,672
2,275
(4,168)
(180)
See Notes to Consolidated Financial Statements.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
169
 
Millions of Dollars
At December 31, 2019
Balance Sheet
ConocoPhillips
ConocoPhillips
Company
Burlington
Resources LLC
All Other
Subsidiaries
Consolidating
Adjustments
Total
Consolidated
Assets
Cash and cash equivalents
$
-
3,439
-
1,649
-
5,088
Short-term investments
-
2,670
-
358
-
3,028
Accounts and notes receivable
5
2,088
2
3,881
(2,575)
3,401
Investment in Cenovus Energy
-
2,111
-
-
-
2,111
Inventories
-
168
-
858
-
1,026
Prepaid expenses and other current assets
1
352
-
1,906
-
2,259
Total Current Assets
6
10,828
2
8,652
(2,575)
16,913
Investments, loans and long-term receivables*
34,076
44,969
11,662
15,612
(97,413)
8,906
Net properties, plants and equipment
-
3,552
-
38,717
-
42,269
Other assets
3
765
253
2,210
(805)
2,426
Total Assets
$
34,085
60,114
11,917
65,191
(100,793)
70,514
Liabilities and Stockholders’ Equity
Accounts payable
$
-
2,670
21
3,084
(2,575)
3,200
Short-term debt
(3)
4
13
91
-
105
Accrued income and other taxes
-
79
-
951
-
1,030
Employee benefit obligations
-
508
-
155
-
663
Other accruals
84
408
35
1,518
-
2,045
Total Current Liabilities
81
3,669
69
5,799
(2,575)
7,043
Long-term debt
3,794
6,670
2,129
2,197
-
14,790
Asset retirement obligations and accrued environmental
 
costs
-
322
-
5,030
-
5,352
Deferred income taxes
-
-
-
5,438
(804)
4,634
Employee benefit obligations
-
1,329
-
452
-
1,781
Other liabilities and deferred credits*
1,787
7,514
826
9,271
(17,534)
1,864
Total Liabilities
5,662
19,504
3,024
28,187
(20,913)
35,464
Retained earnings
33,184
21,898
2,164
10,481
(27,985)
39,742
Other common stockholders’ equity
(4,761)
18,712
6,729
26,454
(51,895)
(4,761)
Noncontrolling interests
-
-
-
69
-
69
Total Liabilities and Stockholders’
 
Equity
$
34,085
60,114
11,917
65,191
(100,793)
70,514
Balance Sheet
At December 31, 2018
Assets
Cash and cash equivalents
$
-
1,428
-
4,487
-
5,915
Short-term investments
-
-
-
248
-
248
Accounts and notes receivable
28
5,646
78
6,707
(8,392)
4,067
Investment in Cenovus Energy
-
1,462
-
-
-
1,462
Inventories
-
184
-
823
-
1,007
Prepaid expenses and other current assets
1
267
-
307
-
575
Total Current Assets
29
8,987
78
12,572
(8,392)
13,274
Investments, loans and long-term receivables*
29,942
47,062
15,199
16,926
(99,465)
9,664
Net properties, plants and equipment
-
4,367
-
41,796
(465)
45,698
Other assets
4
642
227
1,269
(798)
1,344
Total Assets
$
29,975
61,058
15,504
72,563
(109,120)
69,980
Liabilities and Stockholders’ Equity
Accounts payable
$
-
5,098
76
7,113
(8,392)
3,895
Short-term debt
(3)
12
13
99
(9)
112
Accrued income and other taxes
-
85
-
1,235
-
1,320
Employee benefit obligations
-
638
-
171
-
809
Other accruals
85
587
35
552
-
1,259
Total Current Liabilities
82
6,420
124
9,170
(8,401)
7,395
Long-term debt
3,791
7,151
2,143
2,249
(478)
14,856
Asset retirement obligations and accrued environmental
 
costs
-
415
-
7,273
-
7,688
Deferred income taxes
-
-
-
5,819
(798)
5,021
Employee benefit obligations
-
1,340
-
424
-
1,764
Other liabilities and deferred credits*
725
9,277
839
8,126
(17,775)
1,192
Total Liabilities
4,598
24,603
3,106
33,061
(27,452)
37,916
Retained earnings
27,512
18,511
1,113
9,764
(22,890)
34,010
Other common stockholders’ equity
(2,135)
17,944
11,285
29,613
(58,778)
(2,071)
Noncontrolling interests
-
-
-
125
-
125
Total Liabilities and Stockholders’
 
Equity
$
29,975
61,058
15,504
72,563
(109,120)
69,980
*Includes intercompany loans.
 
See Notes to Consolidated Financial Statements.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
170
 
Millions of Dollars
Year Ended
 
December 31, 2019
Statement of Cash Flows
ConocoPhillips
ConocoPhillips
Company
Burlington
Resources LLC
All Other
Subsidiaries
Consolidating
Adjustments
Total
Consolidated
Cash Flows From Operating Activities
Net Cash Provided by Operating Activities
$
1,457
7,986
3,207
9,803
(11,349)
11,104
Cash Flows From Investing Activities
Capital expenditures and investments
-
(2,517)
-
(5,714)
1,595
(6,636)
Working
 
capital changes associated with investing activities
-
37
-
(140)
-
(103)
Proceeds from asset dispositions
2,374
7,047
769
1,055
(8,233)
3,012
Net purchases of investments
-
(2,803)
-
(107)
-
(2,910)
Long-term advances/loans—related parties
-
(812)
-
-
812
-
Collection of advances/loans—related parties
-
141
-
147
(161)
127
Intercompany cash management
1,060
(2,849)
1,402
387
-
-
Other
-
(149)
-
41
-
(108)
Net Cash Provided by (Used in) Investing Activities
3,434
(1,905)
2,171
(4,331)
(5,987)
(6,618)
Cash Flows From Financing Activities
Issuance of debt
-
-
-
812
(812)
-
Repayment of debt
-
(21)
-
(220)
161
(80)
Issuance of company common stock
105
-
-
-
(135)
(30)
Repurchase of company common stock
(3,500)
-
-
-
-
(3,500)
Dividends paid
(1,500)
(4,034)
(454)
(7,097)
11,585
(1,500)
Other
4
-
(4,924)
(1,736)
6,537
(119)
Net Cash Used in Financing Activities
(4,891)
(4,055)
(5,378)
(8,241)
17,336
(5,229)
Effect of Exchange Rate Changes on Cash, Cash Equivalents and
Restricted Cash
-
(11)
-
(35)
-
(46)
Net Change in Cash, Cash Equivalents and Restricted Cash
-
2,015
-
(2,804)
-
(789)
Cash, cash equivalents and restricted cash at beginning
 
of period
-
1,428
-
4,723
-
6,151
Cash, Cash Equivalents and Restricted Cash at End of
 
Period
$
-
3,443
-
1,919
-
5,362
Statement of Cash Flows
Year Ended
 
December 31, 2018*
Cash Flows From Operating Activities
Net Cash
 
Provided by Operating Activities
$
860
4,019
838
14,132
(6,915)
12,934
Cash Flows From Investing Activities
Capital expenditures and investments
-
(980)
(603)
(5,777)
610
(6,750)
Working
 
capital changes associated with investing activities
-
(110)
-
42
-
(68)
Proceeds from asset dispositions
3,457
666
1,926
705
(5,672)
1,082
Net sales of short-term investments
-
-
-
1,620
-
1,620
Long-term advances/loans—related parties
 
-
(126)
(173)
(10)
309
-
Collection of advances/loans—related parties
589
3,432
212
129
(4,243)
119
Intercompany cash management
(803)
3,504
(2,150)
(551)
-
-
Other
-
151
-
3
-
154
Net Cash Provided by (Used in) Investing Activities
3,243
6,537
(788)
(3,839)
(8,996)
(3,843)
Cash Flows From Financing Activities
Issuance
 
of debt
-
10
-
299
(309)
-
Repayment of debt
-
(4,865)
(53)
(4,320)
4,243
(4,995)
Issuance of company common stock
254
-
-
-
(133)
121
Repurchase of company common stock
(2,999)
-
-
-
-
(2,999)
Dividends paid
(1,363)
(1,043)
-
(6,057)
7,100
(1,363)
Other
5
(3,468)
-
(1,670)
5,010
(123)
Net Cash Used in Financing Activities
(4,103)
(9,366)
(53)
(11,748)
15,911
(9,359)
Effect of Exchange Rate Changes on Cash, Cash Equivalents and
Restricted Cash
-
4
-
(121)
-
(117)
Net Change in Cash, Cash Equivalents and Restricted Cash
-
1,194
(3)
(1,576)
-
(385)
Cash, cash equivalents and restricted cash at beginning
 
of period
-
234
3
6,299
-
6,536
Cash, Cash Equivalents and Restricted Cash at End of
 
Period
$
-
1,428
-
4,723
-
6,151
*Revised to reclassify certain intercompany distributions from Operating Activities to 'Proceeds from asset dispositions' within Investing Activities based on the nature of the distributions.
 
There was no impact to Total Consolidated results.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
171
 
Millions of Dollars
Year Ended
 
December 31, 2017
Statement of Cash Flows
ConocoPhillips
ConocoPhillips
Company
Burlington
Resources LLC
All Other
Subsidiaries
Consolidating
Adjustments
Total
Consolidated
Cash Flows From Operating Activities
Net Cash Provided by Operating Activities
$
71
1,183
2,971
5,904
(3,052)
7,077
Cash Flows
 
From Investing Activities
Capital expenditures and investments
-
(1,663)
(4,351)
(3,795)
5,218
(4,591)
Working
 
capital changes associated with investing activities
-
194
-
(62)
-
132
Proceeds from asset dispositions
7,765
11,146
12,178
12,796
(30,025)
13,860
Net purchases of short-term investments
-
-
-
(1,790)
-
(1,790)
Long-term advances/loans—related parties
-
(214)
(65)
(20)
299
-
Collection of advances/loans—related parties
658
1,527
389
2,196
(4,655)
115
Intercompany cash management
1,151
101
(1,341)
89
-
-
Other
-
(8)
-
44
-
36
Net Cash Provided by Investing Activities
9,574
11,083
6,810
9,458
(29,163)
7,762
Cash Flows From Financing Activities
Issuance of debt
-
20
-
279
(299)
-
Repayment of debt
(5,459)
(4,411)
-
(2,661)
4,655
(7,876)
Issuance of company common stock
115
-
-
-
(178)
(63)
Repurchase of company common stock
(3,000)
-
-
-
-
(3,000)
Dividends paid
(1,305)
(235)
-
(2,995)
3,230
(1,305)
Other
4
(7,765)
(9,781)
(7,377)
24,807
(112)
Net Cash Used in Financing Activities
(9,645)
(12,391)
(9,781)
(12,754)
32,215
(12,356)
Effect of Exchange Rate Changes on Cash and Cash Equivalents
-
1
(2)
233
-
232
Net Change in Cash and Cash Equivalents
-
(124)
(2)
2,841
-
2,715
Cash and cash equivalents at beginning of period
-
358
5
3,247
-
3,610
Cash and Cash Equivalents at End of Period
$
-
234
3
6,088
-
6,325
See Notes to Consolidated Financial Statements.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
172
 
PART
 
IV
 
 
Item 15. EXHIBITS, FINANCIAL STATEMENT
 
SCHEDULES
 
 
(a) 1. Financial
 
Statements and Supplementary Data
The financial statements and supplementary information
 
listed in the Index to Financial Statements, which appears
 
on
page 62, are filed as part of this Current Report.
 
 
2. Financial
 
Statement Schedules
Schedule II—Valuation and Qualifying Accounts, appears below.
 
All other schedules are omitted because they are not
required, not significant, not applicable or the information
 
is shown in another schedule, the financial statements
 
or the
notes to consolidated financial statements.
 
 
SCHEDULE II—VALUATION
 
AND QUALIFYING ACCOUNTS (Consolidated)
ConocoPhillips
Millions of Dollars
Balance at
Charged to
Balance at
Description
January 1
Expense
Other
(a)
Deductions
December 31
2019
Deducted from asset accounts:
Allowance for doubtful
 
accounts and notes receivable
$
25
5
-
(17)
(b)
13
Deferred tax asset valuation
 
allowance
3,040
7,376
(26)
(176)
10,214
Included in other liabilities:
Restructuring accruals
48
(1)
-
(24)
(c)
23
2018
Deducted from asset accounts:
Allowance for doubtful
 
accounts and notes receivable
$
4
23
-
(2)
(b)
25
Deferred tax asset valuation
 
allowance
1,254
2,067
(8)
(273)
3,040
Included in other liabilities:
Restructuring accruals
53
70
(2)
(73)
(c)
48
2017
Deducted from asset accounts:
Allowance for doubtful
 
accounts and notes receivable
$
5
2
-
(3)
(b)
4
Deferred tax asset valuation
 
allowance
675
560
19
-
1,254
Included in other liabilities:
Restructuring accruals
80
65
1
(93)
(c)
53
(a)Represents acquisitions/dispositions/revisions
 
and the effect of translating foreign
 
financial statements.
(b)Amounts charged
 
off less recoveries of amounts
 
previously charged
 
off.
(c)Benefit payments.
See Note 19
—
Income Taxes, in the Notes to Consolidated
 
Financial Statements,
 
for additional information
 
related to our deferred
tax asset valuation allowance.
 
 
 
 
 
Exhibit 99.2
 
 
DeGolyer and MacNaughton
5001 Spring Valley
 
Road
Suite 800 East
Dallas, Texas 75244
 
 
February 18, 2020
 
 
ConocoPhillips
 
925 N. Eldridge Parkway
Houston, Texas 77079
 
 
Re: SEC Process Review
 
 
 
Ladies and Gentlemen:
 
Pursuant to your
 
request, DeGolyer and
 
MacNaughton has performed a
 
process review of
 
the processes and
controls used within
 
ConocoPhillips in preparing
 
its internal estimates
 
of proved
 
reserves, as of
 
December 31, 2019.
This process review,
 
which is contemplated by Item
 
1202 (a)(8) of Regulation
 
S–K of the United States
 
Securities and
Exchange Commission
 
(SEC), has been
 
performed specifically
 
to address the
 
adequacy and
 
effectiveness of
ConocoPhillips’ internal processes
 
and controls relative to
 
its estimation
 
of proved reserves in compliance with
Rules 4–10(a) (1)–(32) of Regulation S–X of the SEC.
 
DeGolyer and
 
MacNaughton has
 
participated as
 
an independent
 
member of
 
the internal
 
ConocoPhillips
Reserves Compliance Assessment Team
 
in reviews and
 
discussions with each
 
of the relevant
 
ConocoPhillips business
units relative
 
to SEC
 
proved reserves
 
estimation. DeGolyer
 
and MacNaughton
 
has participated
 
in the
 
review of
 
all
major fields
 
in all
 
countries in
 
which ConocoPhillips
 
has proved
 
reserves worldwide,
 
which ConocoPhillips
 
has
indicated represents over 90 percent of its estimated total proved reserves as of December 31, 2019.
 
 
The reviews with ConocoPhillips’ technical
 
staff involved presentations and
 
discussions of a) basic reservoir
data, including seismic
 
data, well-log data,
 
pressure and production
 
tests, core analysis,
 
pressure-volume-temperature
data, and production history, b) technical methods employed
 
in SEC proved reserves estimation, including performance
analysis, geology,
 
mapping, and volumetric
 
estimates, c) economic analysis,
 
and d) commercial assessment,
 
including
the legal
 
basis for
 
the interest
 
in the
 
reserves, primarily
 
related to
 
lease agreements
 
and other
 
petroleum license
agreements, such as concession and production sharing agreements.
 
A field examination of the properties was not considered necessary for the purposes of this review of
ConocoPhillips’ processes and controls.
 
 
 
It is DeGolyer and MacNaughton’s
 
opinion that ConocoPhillips’ estimates of proved
 
reserves for the
properties reviewed were
 
prepared by the
 
use of recognized
 
geologic and engineering
 
methods generally accepted
 
by
the petroleum industry.
 
The method or combination of
 
methods used in the analysis
 
of each reservoir was tempered
 
by
ConocoPhillips’ experience with
 
similar reservoirs, stage
 
of development, quality
 
and completeness of basic
 
data, and
production history.
 
It is DeGolyer
 
and MacNaughton’s
 
opinion that the
 
general processes and
 
controls employed by
ConocoPhillips in
 
estimating its
 
December 31,
 
2019, proved
 
reserves for
 
the properties
 
reviewed are in
 
accordance
with the SEC reserves definitions.
 
This process
 
review of
 
ConocoPhillips’ procedures
 
and methods
 
does not
 
constitute a
 
review, study,
 
or
independent audit
 
of ConocoPhillips’ estimated
 
proved reserves and
 
corresponding future net
 
revenues. This
 
process
review is not intended
 
to indicate that DeGolyer
 
and MacNaughton is offering
 
any opinion as to
 
the reasonableness of
the reserves estimates reported by ConocoPhillips.
 
DeGolyer and MacNaughton
 
is an independent
 
petroleum engineering consulting
 
firm that has
 
been
providing petroleum consulting services throughout the world since 1936. Neither DeGolyer and MacNaughton nor any
employee who
 
participated in
 
this project
 
has any
 
financial interest,
 
including stock
 
ownership, in
 
ConocoPhillips.
 
DeGolyer and MacNaughton’s fees were not contingent on the results of its evaluation.
 
 
Very
 
truly yours,
 
 
/s/ DeGolyer and MacNaughton
 
DeGOLYER and MacNAUGHTON
Texas Registered Engineering Firm F-716
 
 
/s/ Charles F.
 
Boyette
 
Charles F. Boyette, P.E.
President
DeGolyer and MacNaughton